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, 2014

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, 2014, 176,993,343 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, 2014

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)	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3. Quantitative and Qualitative Disclosures About Market Risk	50
Item 4. Controls and Procedures	52
PART II - OTHER INFORMATION
Item 1. Legal Proceedings	53
Item 1A. Risk Factors	54
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 6. Exhibits	55
SIGNATURE	56
EX-4-284
EX-10-90
EX-10-91
EX-12-58
EX-31-91
EX-31-92
EX-32-91
EX-32-92
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

CFTC	U.S. Commodity Futures Trading Commission
Citizens	Citizens Fuel Gas Company, which distributes natural gas in Adrian, Michigan
Company	DTE Energy Company and any subsidiary companies
Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity and natural gas.
DTE Electric	DTE Electric Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies.
DTE Energy	DTE Energy Company, directly or indirectly the parent of DTE Electric, DTE Gas and numerous non-utility subsidiaries.
DTE Gas	DTE Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies.
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FOV	Finding of Violation
FTRs	Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
GCR	A Gas Cost Recovery mechanism authorized by the MPSC that allows DTE Gas to recover through rates its natural gas costs.
MDEQ	Michigan Department of Environmental Quality
MISO	Midcontinent Independent System Operator, Inc.
MPSC	Michigan Public Service Commission
MTM	Mark-to-market
Non-utility	An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC.
NOV	Notice of Violation
NRC	U.S. Nuclear Regulatory Commission
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
BTU	Heat value (energy content) of fuel
kWh	Kilowatthour of electricity
MMBtu	One million BTU
MWh	Megawatthour of electricity

2

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

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

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

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

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

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

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

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

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

• unplanned outages;

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

• employee relations and the impact of collective bargaining agreements;

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

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

• the effects of competition;

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

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

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

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

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

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,
	2014			2013			2014			2013
	(In millions, except per share amounts)
Operating Revenues	$	2,698		$	2,225		$	6,628		$	4,741
Operating Expenses
Fuel, purchased power and gas	1,276			940			3,431			1,964
Operation and maintenance	811			705			1,652			1,440
Depreciation, depletion and amortization	282			268			562			527
Taxes other than income	87			84			182			178
Asset (gains) and losses, reserves and impairments, net	(7		)	5			(8		)	(1		)
	2,449			2,002			5,819			4,108
Operating Income	249			223			809			633
Other (Income) and Deductions
Interest expense	106			112			216			221
Interest income	(3		)	(3		)	(5		)	(5		)
Other income	(40		)	(46		)	(81		)	(90		)
Other expenses	10			9			18			16
	73			72			148			142
Income Before Income Taxes	176			151			661			491
Income Tax Expense	50			44			208			149
Net Income	126			107			453			342
Less: Net Income Attributable to Noncontrolling Interest	2			2			3			3
Net Income Attributable to DTE Energy Company	$	124		$	105		$	450		$	339
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	0.70		$	0.60		$	2.54		$	1.94
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	0.70		$	0.60		$	2.54		$	1.94
Weighted Average Common Shares Outstanding
Basic	177			174			177			174
Diluted	177			175			177			174
Dividends Declared per Common Share	$	0.66		$	0.66		$	1.31		$	1.28

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,
	2014		2013			2014		2013
	(In millions)
Net income	$	126	$	107		$	453	$	342
Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $1, $1, $1 and $2, respectively	1		2			1		5
Net unrealized gains on investments during the period, net of taxes of $—, $—, $— and $—, respectively	1		—			1		—
Foreign currency translation, net of taxes of $1, $(1), $— and $(1), respectively	1		(1		)	—		(2		)
Other comprehensive income	3		1			2		3
Comprehensive income	129		108			455		345
Less comprehensive income attributable to noncontrolling interests	2		2			3		3
Comprehensive income attributable to DTE Energy Company	$	127	$	106		$	452	$	342

See Notes to Consolidated Financial Statements (Unaudited)

5

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)

	June 30,			December 31,
	2014			2013
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	75		$	52
Restricted cash, principally Securitization	110			123
Accounts receivable (less allowance for doubtful accounts of $60 and $55, respectively)
Customer	1,400			1,542
Other	126			127
Inventories
Fuel and gas	342			363
Materials and supplies	277			265
Derivative assets	98			99
Regulatory assets	127			26
Other	166			209
	2,721			2,806
Investments
Nuclear decommissioning trust funds	1,237			1,191
Other	604			603
	1,841			1,794
Property
Property, plant and equipment	25,836			25,123
Less accumulated depreciation, depletion and amortization	(9,529		)	(9,323		)
	16,307			15,800
Other Assets
Goodwill	2,018			2,018
Regulatory assets	2,719			2,837
Securitized regulatory assets	135			231
Intangible assets	112			122
Notes receivable	90			102
Derivative assets	26			27
Other	220			198
	5,320			5,535
Total Assets	$	26,189		$	25,935

See Notes to Consolidated Financial Statements (Unaudited)

6

DTE Energy Company

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

	June 30,			December 31,
	2014			2013
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	946		$	962
Accrued interest	86			90
Dividends payable	238			116
Short-term borrowings	511			131
Current portion long-term debt, including capital leases	229			898
Derivative liabilities	148			195
Gas inventory equalization	38			—
Regulatory liabilities	150			302
Other	473			495
	2,819			3,189
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	7,329			6,618
Securitization bonds	—			105
Junior subordinated debentures	480			480
Capital lease obligations	4			11
	7,813			7,214
Other Liabilities
Deferred income taxes	3,500			3,321
Regulatory liabilities	757			862
Asset retirement obligations	1,883			1,827
Unamortized investment tax credit	42			47
Derivative liabilities	29			43
Accrued pension liability	564			653
Accrued postretirement liability	307			350
Nuclear decommissioning	180			178
Other	269			297
	7,531			7,578
Commitments and Contingencies (Notes 7 and 11)
Equity
Common stock, without par value, 400,000,000 shares authorized, 176,993,343 and 177,087,230 shares issued and outstanding, respectively	3,896			3,907
Retained earnings	4,246			4,150
Accumulated other comprehensive loss	(134		)	(136		)
Total DTE Energy Company Equity	8,008			7,921
Noncontrolling interests	18			33
Total Equity	8,026			7,954
Total Liabilities and Equity	$	26,189		$	25,935

See Notes to Consolidated Financial Statements (Unaudited)

7

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
	2014			2013
	(In millions)
Operating Activities
Net income	$	453		$	342
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	562			527
Nuclear fuel amortization	19			17
Allowance for equity funds used during construction	(11		)	(6		)
Deferred income taxes	196			123
Asset (gains) and losses, reserves and impairments, net	(7		)	—
Changes in assets and liabilities:
Accounts receivable, net	145			70
Inventories	9			133
Accounts payable	104			(29		)
Gas inventory equalization	38			73
Accrued pension obligation	(89		)	(42		)
Accrued postretirement obligation	(43		)	(174		)
Derivative assets and liabilities	(59		)	(15		)
Regulatory assets and liabilities	(224		)	226
Other assets	35			71
Other liabilities	(52		)	(49		)
Net cash from operating activities	1,076			1,267
Investing Activities
Plant and equipment expenditures — utility	(924		)	(708		)
Plant and equipment expenditures — non-utility	(156		)	(197		)
Proceeds from sale of assets	31			15
Restricted cash for debt redemption, principally Securitization	13			10
Proceeds from sale of nuclear decommissioning trust fund assets	475			309
Investment in nuclear decommissioning trust funds	(483		)	(317		)
Other	(23		)	(23		)
Net cash used for investing activities	(1,067		)	(911		)
Financing Activities
Issuance of long-term debt, net of issuance costs	595			371
Redemption of long-term debt	(664		)	(515		)
Short-term borrowings, net	380			(24		)
Issuance of common stock	—			19
Repurchase of common stock	(52		)	—
Dividends on common stock	(232		)	(215		)
Other	(13		)	(11		)
Net cash from (used for) financing activities	14			(375		)
Net Increase (Decrease) in Cash and Cash Equivalents	23			(19		)
Cash and Cash Equivalents at Beginning of Period	52			65
Cash and Cash Equivalents at End of Period	$	75		$	46
Supplemental disclosure of non-cash investing and financing activities
Plant and equipment expenditures in accounts payable	$	209		$	218

See Notes to Consolidated Financial Statements (Unaudited)

8

DTE Energy Company

Consolidated Statements of Changes in Equity (Unaudited)

									Accumulated Other Comprehensive Loss			Non-Controlling Interests
	Common Stock					Retained Earnings
	Shares		Amount												Total
	(Dollars in millions, shares in thousands)
Balance, December 31, 2013	177,087		$	3,907		$	4,150		$	(136	)	$	33		$	7,954
Net income	—		—			450			—			3			453
Dividends declared on common stock	—		—			(354		)	—			—			(354		)
Repurchase of common stock	(713	)	(52		)	—			—			—			(52		)
Benefit obligations, net of tax	—		—			—			1			—			1
Net change in unrealized losses on investments, net of tax	—		—			—			1			—			1
Stock-based compensation, distributions to noncontrolling interests and other	619		41			—			—			(18		)	23
Balance, June 30, 2014	176,993		$	3,896		$	4,246		$	(134	)	$	18		$	8,026

See 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, the MDEQ and the CFTC.

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 2013 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 present 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, 2014.

Certain prior year balances were reclassified to match the current year’s financial statement presentation. Such revisions included an increase in the Consolidated Statements of Cash Flows line items for (i) Proceeds from sale of nuclear decommissioning trust funds, and (ii) Investment in nuclear decommissioning trust funds by $282 million for the six months ended June 30, 2013. These revisions were needed to properly state the gross purchases and sales activity in the nuclear decommissioning trust fund for the six months ended June 30, 2013. The total of Net cash used in investing activities for the six months ended June 30, 2013 was unchanged by these revisions. The revisions noted above are not deemed material, individually or in the aggregate, to the prior period consolidated financial statements.

Principles of Consolidation

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

9

DTE Energy Company

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

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

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

The Company has variable interests in VIEs through certain of its long-term purchase and sale contracts. As of June 30, 2014, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase and sale contracts are predominately related to working capital accounts and generally represent the amounts owed by or to the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any significant form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase and sale contracts.

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

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

10

DTE Energy Company

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

The following table summarizes the major balance sheet items for consolidated VIEs as of June 30, 2014 and December 31, 2013. All assets and liabilities of a consolidated VIE are presented where it has been determined that aconsolidated VIE has either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.

	June 30, 2014						December 31, 2013
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	14	$	14	$	—	$	12	$	12
Restricted cash	88		6		94		100		8		108
Accounts receivable	39		12		51		34		16		50
Inventories	—		27		27		—		118		118
Property, plant and equipment, net	—		86		86		—		99		99
Securitized regulatory assets	135		—		135		231		—		231
Other current and long-term assets	2		7		9		4		9		13
	$	264	$	152	$	416	$	369	$	262	$	631
LIABILITIES
Accounts payable and accrued current liabilities	$	5	$	8	$	13	$	7	$	23	$	30
Current portion long-term debt, including capital leases	201		9		210		196		9		205
Current regulatory liabilities	41		—		41		43		—		43
Mortgage bonds, notes and other	—		18		18		—		21		21
Securitization bonds	—		—		—		105		—		105
Capital lease obligations	—		4		4		—		7		7
Other current and long-term liabilities	8		5		13		8		6		14
	$	255	$	44	$	299	$	359	$	66	$	425

Amounts for non-consolidated VIEs as of June 30, 2014 and December 31, 2013 are as follows:

	June 30, 2014		December 31, 2013
	(In millions)
Other investments	$	130	$	141
Notes receivable	$	13	$	8

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Other Income

Other income is recognized for non-operating income such as equity earnings, interest and dividends, allowance for funds used during construction and contract services. Power & Industrial Projects also recognizes Other income in connection with the sale of membership interests in reduced emissions fuel facilities to investors. In exchange for the cash received, the investors will receive a portion of the economic attributes of the facilities, including income tax attributes. The transactions are not treated as a sale of membership interests for financial reporting purposes. Other income is considered earned when refined coal is produced and tax credits are generated. Power & Industrial Projects recognized approximately $15 million and $20 million of Other income for the three months ended June 30, 2014 and 2013, respectively, and approximately $32 million and $35 million of Other income for the six months ended June 30, 2014 and 2013, respectively.

11

DTE Energy Company

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

Comprehensive Income (Loss)

Comprehensive income (loss) is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following tables, amounts recorded to accumulated other comprehensive loss for the three and six months ended June 30, 2014 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, 2014
	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, 2014	$	(4	)	$	(6	)	$	(126	)	$	(1	)	$	(137	)
Other comprehensive income before reclassifications	—			1			—			1			2
Amounts reclassified from accumulated other comprehensive income	—			—			1			—			1
Net current-period other comprehensive income	—			1			1			1			3
Ending balance, June 30, 2014	$	(4	)	$	(5	)	$	(125	)	$	—		$	(134	)

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Six Months Ended June 30, 2014
	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, 2013	$	(4	)	$	(6	)	$	(126	)	$	—	$	(136	)
Other comprehensive income before reclassifications	—			1			(2		)	—		(1		)
Amounts reclassified from accumulated other comprehensive income	—			—			3			—		3
Net current-period other comprehensive income	—			1			1			—		2
Ending balance, June 30, 2014	$	(4	)	$	(5	)	$	(125	)	$	—	$	(134	)

______________________________________

(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 and other postretirement benefits cost (see Note 12).

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,
	2014		2013
	(In millions)
Emission allowances	$	2	$	2
Renewable energy credits	51		51
Contract intangible assets	123		126
	176		179
Less accumulated amortization	51		45
Intangible assets, net	125		134
Less current intangible assets	13		12
	$	112	$	122

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 1 to 28 years.

Income Taxes

The Company's effective tax rate for the three months ended June 30, 2014 was 28% as compared to 29% for the three months ended June 30, 2013. The Company's effective tax rate for the six months ended June 30, 2014 was 31% as compared to 30% for the six months ended June 30, 2013. The 1% decrease in the effective tax rate for the three months ended June 30, 2014 is due to higher production tax credits. The 1% increase in effective tax rate for the six months ended June 30, 2014 is due to $8 million of deferred tax expense resulting from New York state income tax reform enacted on March 31, 2014, partially offset by higher production tax credits.

The Company had $2 million of unrecognized tax benefits at June 30, 2014, 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.

NOTE 3 — NEW ACCOUNTING PRONOUNCEMENTS

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

13

DTE Energy Company

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

NOTE 4 — 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, 2014 and December 31, 2013. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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

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

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

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, 2014 and December 31, 2013:

	June 30, 2014															December 31, 2013
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	12		$	96		$	—		$	—		$	108		$	10		$	115		$	—		$	—		$	125
Nuclear decommissioning trusts	798			439			—			—			1,237			779			412			—			—			1,191
Other investments (c) (d)	94			50			—			—			144			92			44			—			—			136
Derivative assets:
Commodity Contracts:
Natural Gas	118			101			52			(259		)	12			273			89			34			(382		)	14
Electricity	—			498			95			(487		)	106			—			261			139			(291		)	109
Other	35			3			7			(39		)	6			33			1			3			(34		)	3
Total derivative assets	153			602			154			(785		)	124			306			351			176			(707		)	126
Total	$	1,057		$	1,187		$	154		$	(785	)	$	1,613		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(123	)	$	(123	)	$	(72	)	$	264		$	(54	)	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)
Electricity	—			(484		)	(122		)	484			(122		)	—			(272		)	(126		)	269			(129		)
Other	(32		)	(7		)	—			39			—			(32		)	(2		)	—			34			—
Other derivative contracts (f)	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(155		)	(615		)	(194		)	787			(177		)	(309		)	(415		)	(212		)	698			(238		)
Total	$	(155	)	$	(615	)	$	(194	)	$	787		$	(177	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	902		$	572		$	(40	)	$	2		$	1,436		$	878		$	507		$	(36	)	$	(9	)	$	1,340
Assets:
Current	$	145		$	618		$	123		$	(680	)	$	206		$	277		$	400		$	139		$	(592	)	$	224
Noncurrent (e)	912			569			31			(105		)	1,407			910			522			37			(115		)	1,354
Total Assets	$	1,057		$	1,187		$	154		$	(785	)	$	1,613		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Current	$	(133	)	$	(528	)	$	(169	)	$	682		$	(148	)	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)
Noncurrent	(22		)	(87		)	(25		)	105			(29		)	(41		)	(87		)	(35		)	120			(43		)
Total Liabilities	$	(155	)	$	(615	)	$	(194	)	$	787		$	(177	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	902		$	572		$	(40	)	$	2		$	1,436		$	878		$	507		$	(36	)	$	(9	)	$	1,340

_______________________________________

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

(b) At June 30, 2014, available-for-sale securities of $108 million included $95 million and $13 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2013, available-for-sale securities of $125 million, included $109 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available-for-sale equity securities of $7 million at both June 30, 2014 and December 31, 2013, are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $144 million and $136 million at June 30, 2014 and December 31, 2013, respectively, of other investments that are included in the Consolidated Statements of Financial Position in Other investments.

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

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of short-term investments and money market funds.

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 hold exchange-traded equity or debt securities and are valued based on stated net asset values (NAV). Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustee monitors prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustee determines that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair value of securities by comparison of market-based price sources. Investment policies and procedures are determined by the Company's Trust Investments Department which reports to the Company's Vice President and Treasurer.

Derivative Assets and Liabilities

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30, 2014												Three Months Ended June 30, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of April 1	$	(10	)	$	(34	)	$	1		$	(43	)	$	(34	)	$	(9	)	$	2		$	(41	)
Transfers into Level 3	—			—			—			—			—			—			—			—
Transfers out of Level 3	—			—			—			—			—			—			—			—
Total gains (losses):
Included in earnings	(16		)	(22		)	(1		)	(39		)	(2		)	18			(1		)	15
Recorded in regulatory assets/liabilities	—			—			7			7			—			—			3			3
Purchases, issuances and settlements:
Issuances	—			(1		)	—			(1		)	—			—			—			—
Settlements	6			30			—			36			6			3			(2		)	7
Net Assets (Liabilities) as of June 30	$	(20	)	$	(27	)	$	7		$	(40	)	$	(30	)	$	12		$	2		$	(16	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(11	)	$	1		$	—		$	(10	)	$	(1	)	$	33		$	(1	)	$	31

16

DTE Energy Company

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

	Six Months Ended June 30, 2014												Six Months Ended June 30, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of January 1	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
Transfers into Level 3	—			—			—			—			—			—			—			—
Transfers out of Level 3	—			—			—			—			(2		)	—			—			(2		)
Total gains (losses):
Included in earnings	(38		)	20			(1		)	(19		)	(10		)	26			(1		)	15
Recorded in regulatory assets/liabilities	—			—			11			11			—			—			4			4
Purchases, issuances and settlements:
Purchases	—			—			—			—			—			1			—			1
Issuances	—			(2		)	—			(2		)	—			—			—			—
Settlements	70			(58		)	(6		)	6			20			(38		)	(3		)	(21		)
Net Assets (Liabilities) as of June 30	$	(20	)	$	(27	)	$	7		$	(40	)	$	(30	)	$	12		$	2		$	(16	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(11	)	$	(19	)	$	—		$	(30	)	$	(6	)	$	27		$	(1	)	$	20

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 and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30, 2014					Three Months Ended June 30, 2013
	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		—	—		N/A

	Six Months Ended June 30, 2014					Six Months Ended June 30, 2013
	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		2
Transfers into Level 3 from	—	—		N/A		—	—		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of June 30, 2014:

	June 30, 2014
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	52	$	(72	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.80	)	—	$	6.98	/MMBtu	$	(0.11	)/MMBtu
Electricity	$	95	$	(122	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(3	)	—	$	16	/MWh	$	4	/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, 2013:

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

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2014 and December 31, 2013:

	June 30, 2014								December 31, 2013
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	46	$	—	$	—	$	46	$	41	$	—	$	—	$	41
Dividends payable	$	238	$	238	$	—	$	—	$	116	$	116	$	—	$	—
Short-term borrowings	$	511	$	—	$	511	$	—	$	131	$	—	$	131	$	—
Long-term debt, excluding capital leases	$	8,030	$	483	$	7,511	$	801	$	8,094	$	425	$	7,551	$	499

See Note 5 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, 2014		December 31, 2013
	(In millions)
Fermi 2	$	1,214	$	1,172
Fermi 1	3		3
Low level radioactive waste	20		16
Total	$	1,237	$	1,191

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions)
Realized gains	$	7		$	11		$	16		$	19
Realized losses	$	(4	)	$	(7	)	$	(11	)	$	(14	)
Proceeds from sales of securities	$	204		$	173		$	475		$	309

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, 2014				December 31, 2013
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	762	$	220	$	730	$	201
Debt securities	462		19		442		12
Cash and cash equivalents	13		—		19		—
	$	1,237	$	239	$	1,191	$	213

The debt securities at June 30, 2014 and December 31, 2013 had an average maturity of approximately 7 years, respectively. Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As DTE Electric does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be other-than-temporary impairments.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. DTE Electric recognized $28 million and $31 million of unrealized losses as Regulatory assets at June 30, 2014 and December 31, 2013, 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, 2014 and 2013 for Fermi 1.

Other Securities

At June 30, 2014 and December 31, 2013, the securities were comprised primarily of money market and equity securities. During the three and six months ended June 30, 2014 and 2013, no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income and realized into net income for the periods. Gains related to trading securities held at June 30, 2014 and 2013 were $8 million and $9 million, respectively.

19

DTE Energy Company

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

NOTE 5 — 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 fair value are recognized in earnings each period.

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

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

Gas — DTE Gas purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. DTE Gas has fixed-priced contracts for portions of its expected natural gas supply requirements through March 2017. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. DTE Gas may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are generally not derivatives and are therefore accounted for under the accrual method.

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

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

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity, 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.

20

DTE Energy Company

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

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

Credit Risk — The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its June 30, 2014 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

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

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

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

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

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

21

DTE Energy Company

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

The following tables present the fair value of derivative instruments as of June 30, 2014 and December 31, 2013:

	June 30, 2014					December 31, 2013
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	(1	)	$	—	$	(1	)
Commodity Contracts:
Natural Gas	271		(318		)	396		(503		)
Electricity	593		(606		)	400		(398		)
Other	45		(39		)	37		(34		)
Total derivatives not designated as hedging instruments:	$	909	$	(964	)	$	833	$	(936	)
Total derivatives:
Current	$	778	$	(830	)	$	691	$	(773	)
Noncurrent	131		(134		)	142		(163		)
Total derivatives	$	909	$	(964	)	$	833	$	(936	)

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

The Company also provides and receives collateral in the form of letters of credit which can be offset against net derivative assets and liabilities as well as accounts receivable and payable. The Company had issued letters of credit of approximately $18 million and $19 million at June 30, 2014 and December 31, 2013, respectively, which could be used to offset net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were 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, 2014, the total cash collateral posted, net of cash collateral received, was $26 million. As of December 31, 2013, the total cash collateral posted, net of cash collateral received, was $12 million. As of June 30, 2014, derivative assets and derivative liabilities are shown net of cash collateral of $5 million and $7 million, respectively. As of December 31, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $26 million and $17 million, respectively. The Company recorded cash collateral paid of $30 million and cash collateral received of $6 million not related to unrealized derivative positions as of June 30, 2014. The Company recorded cash collateral paid of $34 million and cash collateral received of $13 million not related to unrealized derivative positions as of December 31, 2013. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

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, 2014 and December 31, 2013:

	June 30, 2014									December 31, 2013
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	271		$	(259	)	$	12		$	396		$	(382	)	$	14
Electricity	593			(487		)	106			400			(291		)	109
Other	45			(39		)	6			37			(34		)	3
Total derivative assets	$	909		$	(785	)	$	124		$	833		$	(707	)	$	126
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(318	)	$	264		$	(54	)	$	(503	)	$	395		$	(108	)
Electricity	(606		)	484			(122		)	(398		)	269			(129		)
Other	(39		)	39			—			(34		)	34			—
Other derivative liabilities	(1		)	—			(1		)	(1		)	—			(1		)
Total derivative liabilities	$	(964	)	$	787		$	(177	)	$	(936	)	$	698		$	(238	)

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2014 and December 31, 2013:

	June 30, 2014												December 31, 2013
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	778		$	131		$	(830	)	$	(134	)	$	691		$	142		$	(773	)	$	(163	)
Counterparty netting	(675		)	(105		)	675			105			(566		)	(115		)	566			115
Collateral adjustment	(5		)	—			7			—			(26		)	—			12			5
Total derivatives as reported	$	98		$	26		$	(148	)	$	(29	)	$	99		$	27		$	(195	)	$	(43	)

23

DTE Energy Company

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

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013 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		2014			2013			2014			2013
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	3		$	(1	)	$	(1	)	$	(1	)
Commodity Contracts:
Natural Gas	Operating Revenue	155			46			28			36
Natural Gas	Fuel, purchased power and gas	(9		)	(46		)	11			(32		)
Electricity	Operating Revenue	(45		)	10			88			30
Other	Operating Revenue	(3		)	(1		)	(4		)	—
Total		$	101		$	8		$	122		$	33

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 following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2014:

Commodity	Number of Units
Natural Gas (MMBtu)	815,660,484
Electricity (MWh)	19,527,918
Oil (Gallons)	11,592,000
Foreign Currency Exchange ($ CAD)	79,076,508

Various subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to require that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be required to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily natural gas, power and coal) and the provisions and maturities of the underlying transactions. As of June 30, 2014, DTE Energy's contractual obligation to post collateral in the form of cash or letter of credit in the event of a downgrade to below investment grade, under both hard trigger and soft trigger provisions, was approximately $331 million.

As of June 30, 2014, the Company had approximately $1,082 million of derivatives in net liability positions, for which hard triggers exist. Collateral of approximately $18 million has been posted against such liabilities, including cash and letters of credit. Associated derivative net asset positions for which contractual offset exists were approximately $962 million. The net remaining amount of approximately $102 million is derived from the $331 million noted above.

24

DTE Energy Company

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

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2014 follows:

	(In millions)
Asset retirement obligations at December 31, 2013	$	1,827
Accretion	56
Liabilities incurred	9
Liabilities settled	(4		)
Revision in estimated cash flows	(5		)
Asset retirement obligations at June 30, 2014	$	1,883

NOTE 7 — REGULATORY MATTERS

Refundable Revenue Decoupling/ Deferred Gain Amortization

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

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

Transitional Reconciliation Mechanism (TRM)

On July 19, 2013, DTE Electric filed its TRM application proposing a transitional tariff option for certain former PLD customers and a modified line extension provision. The application also proposed a recovery mechanism for the deferred net incremental revenue requirement associated with the transition. The net incremental revenue requirement includes costs to install meters and attach customers; system and customer facility upgrades and repairs; and the difference between DTE Electric's tariff rates and any transitional rates approved in the future. On May 13, 2014, the MPSC approved the TRM as requested and also ordered DTE Electric to include in the TRM the PLD transmission delivery service costs incurred while DTE Electric is temporarily relying upon PLD to operate and maintain PLD's system during the system conversion period. The meter installation phase of the transition was completed in June 2014. On July 1, 2014, former PLD customers became customers of DTE Electric.

PSCR Proceedings

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

2012 PSCR Year — In March 2013, DTE Electric filed the 2012 PSCR reconciliation calculating a net under-recovery of approximately $87 million that includes an under-recovery of approximately $148 million for the 2011 PSCR year. The reconciliation includes purchased power costs related to the manual shutdown of our Fermi 2 nuclear power plant in June 2012 caused by the failure of one of the plant's two non-safety related feed-water pumps. The plant was restarted on July 30, 2012, which restored production to nominal 68% of full capacity. In September 2013, the repair to the plant was completed and production was returned to full capacity. DTE Electric was able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. Certain intervenors in the reconciliation case have challenged the recovery of up to $32 million of the Fermi-related purchased power costs. Resolution of this matter is expected by late 2014 or early 2015.

25

DTE Energy Company

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

NOTE 8 — 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 and six months ended June 30:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014		2013			2014		2013
	(In millions, except per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	124	$	105		$	450	$	339
Average number of common shares outstanding	177		174			177		174
Weighted average net restricted shares outstanding	—		1			—		1
Dividends declared — common shares	$	116	$	114		$	231	$	222
Dividends declared — net restricted shares	—		1			1		—
Total distributed earnings	$	116	$	115		$	232	$	222
Net income less distributed earnings	$	8	$	(10	)	$	218	$	117
Distributed (dividends per common share)	$	0.66	$	0.66		$	1.31	$	1.28
Undistributed	0.04		(0.06		)	1.23		0.66
Total Basic Earnings per Common Share	$	0.70	$	0.60		$	2.54	$	1.94
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	124	$	105		$	450	$	339
Average number of common shares outstanding	177		175			177		174
Weighted average net restricted shares outstanding	—		1			—		1
Dividends declared — common shares	$	116	$	114		$	231	$	222
Dividends declared — net restricted shares	—		1			1		—
Total distributed earnings	$	116	$	115		$	232	$	222
Net income less distributed earnings	$	8	$	(10	)	$	218	$	117
Distributed (dividends per common share)	$	0.66	$	0.66		$	1.31	$	1.28
Undistributed	0.04		(0.06		)	1.23		0.66
Total Diluted Earnings per Common Share	$	0.70	$	0.60		$	2.54	$	1.94

NOTE 9 — LONG-TERM DEBT

Debt Issuances

In 2014, the following debt was issued:

Company	Month	Type	Interest Rate	Maturity	Amount
					(In millions)
DTE Energy	May	Senior Notes (a)	3.50%	2024	$	350
DTE Electric	June	Mortgage Bonds (a)	3.77%	2026	100
DTE Electric	June	Mortgage Bonds (a)	4.60%	2044	150
					$	600

_______________________________________

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

In July 2014, DTE Electric issued $350 million of 3.375% mortgage bonds due 2025 and $350 million of 4.30% mortgage bonds due 2044. Proceeds will be used for redemption of DTE Electric long-term debt, for the repayment of short-term borrowings and for general corporate purposes.

26

DTE Energy Company

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

Debt Redemptions

In 2014, the following debt was redeemed:

Company	Month	Type	Interest Rate	Maturity	Amount
					(In millions)
DTE Electric	March	Mortgage Bonds	Various	2014	$	13
DTE Electric	March	Securitization Bonds	6.62%	2014	100
DTE Electric	April	Tax Exempt Revenue Bonds (a)	2.35%	2024	31
DTE Electric	April	Tax Exempt Revenue Bonds (a)	4.65%	2028	32
DTE Gas	May	Mortgage Bonds	8.25%	2014	80
DTE Energy	May	Senior Notes	7.625%	2014	300
DTE Electric	June	Tax Exempt Revenue Bonds (a)	4.875%	2029	36
DTE Electric	June	Tax Exempt Revenue Bonds (a)	6.00%	2036	69
DTE Energy	Various	Other Long Term Debt	Various	2014	3
					$	664

_______________________________________

(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 Tax Exempt Revenue Bonds.

In June 2014, DTE Electric called for redemption $200 million of 4.80% senior notes due in February 2015 to be redeemed in July 2014 and $60 million of 5.25% tax exempt revenue bonds due in August 2029 to be redeemed in August 2014.

NOTE 10 — 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, 2014, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.49 to 1, 0.52 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, 2014 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in February 2015	$	100	$	—	$	—	$	100
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,425		300		300		2,025
Amounts outstanding at June 30, 2014:
Commercial paper issuances	236		275		—		511
Letters of credit	208		—		—		208
	444		275		—		719
Net availability at June 30, 2014	$	981	$	25	$	300	$	1,306

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $36 million which are used for various corporate purposes.

27

DTE Energy Company

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

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At June 30, 2014, a $50 million letter of credit was in place, raising the capacity under this facility to $150 million. The $50 million letter of credit is included in the table above. The amount outstanding under this agreement was $47 million and $138 million at June 30, 2014 and December 31, 2013, respectively.

NOTE 11 — 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 $2 billion through 2013. The Company estimates DTE Electric will make capital expenditures of approximately $280 million in 2014 and up to approximately $1.2 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and other hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, 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 (Court of Appeals) 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 of Appeals issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the 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 for a review of the Court of Appeals' decision on CSAPR. On April 29, 2014, the U.S. Supreme Court issued its ruling reversing the Court of Appeals' stay decision and remanding the case for further proceedings. The EPA has since requested the Court of Appeals to lift the stay on CSAPR and proposed that phase one of the rule would start effective January 2015. Notwithstanding the U.S. Supreme Court remand decision and potential decision by the Court of Appeals to lift the stay, DTE Electric expects to meet its obligations under CSAPR beginning in 2015. Furthermore, the EPA and a number of states, including Michigan, have started working on the framework of revised CSAPR regulations which may still be proposed in the next few years to address other challenges to the existing CSAPR regulations. DTE Electric will continue to monitor these developments and adjust its compliance strategy accordingly.

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

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

28

DTE Energy Company

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

In August 2010, the U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. On March 28, 2013, the Court of Appeals remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements. On September 3, 2013, the EPA caused to be filed a motion seeking leave to amend their complaint regarding the June 2010 NOV/FOV adding additional claims related to outage work performed at the Trenton Channel and Belle River power plants as well as additional claims related to work performed at the Monroe Power Plant. In addition, the Sierra Club caused to be filed a motion to add a claim regarding the River Rouge Power Plant. On March 3, 2014, the U.S. District Court judge granted again DTE Energy's motion for summary judgment dismissing the civil case related to Monroe Unit 2. On April 3, 2014, the U.S. District Court judge granted motions filed by the EPA and the Sierra Club to amend their New Source Review complaint adding additional claims for Monroe Units 1, 2 and 3, Belle River Units 1 and 2, Trenton Channel Unit 9 and River Rouge Unit 3. On June 30, 2014, the EPA filed a motion requesting certification for appeal of the March 3, 2014 summary judgment decision.

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

In March 2013, the Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499six-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the court enjoin DTE Energy and DTE Electric from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. In December 2013, a U.S. District Court judge issued an order dismissing, without prejudice, the plaintiff's complaint allowing them to file an amended complaint by January 17, 2014. The order dismissing the complaint resulted from a considerable number of plaintiff's claims being time barred based on the statute of limitations. On January 17, 2014, the plaintiffs filed an amended complaint for the period January 13, 2008 - June 30, 2012, reducing the total number of six-minute periods from 1,499 to 1,139. DTE Energy and DTE Electric filed an answer to the amended complaint on March 11, 2014. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

Water — In response to an EPA regulation, DTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The final rule was issued on May 19, 2014. The final rule specifies a time period exceeding three years to complete studies to determine the type of technology needed to reduce impacts to fish. Final compliance for the installation of the required technology will be determined by each state on a case by case basis. We are currently evaluating the compliance options and working with the State of Michigan on evaluating whether any controls are needed. These evaluations/studies may require modifications to some existing intake structures. It is not possible to quantify the impact of this rulemaking at this time.

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 September 2015. DTE Electric has provided comments to the EPA. However, it is not possible at this time to quantify the impacts of these developing requirements.

29

DTE Energy Company

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

Contaminated and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as 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 MGP site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At June 30, 2014 and December 31, 2013, the Company had $8 million accrued for remediation, respectively. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company believes the likelihood of a material change to the accrued amount is remote based on current knowledge of the conditions at each site.

DTE Electric owns and operates three permitted engineered ash storage facilities to dispose of fly ash from the coal fired power plants. The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published in June 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. The rules are expected to be finalized by December 2014. It is not possible to quantify the impact of those expected rulemakings at this time.

Gas

Contaminated and Other Sites — Gas segment owns or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. Cleanup of two of the MGP sites is complete and the sites are closed. Partial or complete closure of four additional sites is being pursued in 2014. Cleanup activities associated with the remaining sites will be continued over the next several years. The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. As of June 30, 2014 and December 31, 2013, the Company had $24 million and $28 million accrued for remediation, respectively. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-utility

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

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

30

DTE Energy Company

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

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 $4 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company will also spend up to an additional $15 million over the next few years to upgrade the treatment technology to biological treatment to meet future regulatory requirements and gain other operational improvement savings.

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

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

Other

In December 2012, 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). Capital costs for pollution controls and/or boiler conversions and the expenses for the one-time energy assessments are not expected to be material.

In 2010, the EPA finalized a new 1-hour sulfur dioxide ambient air quality standard that requires states to submit plans for non-attainment areas to be in compliance by 2017. Michigan's non-attainment area includes DTE Energy facilities in southwest Detroit and areas of Wayne County. Preliminary modeling runs by the MDEQ suggest that emission reductions may be required by significant sources of sulfur dioxide emissions in these areas, including DTE Electric power plants and our Michigan coke battery. The state implementation plan process is in the information gathering stage, and DTE Energy is unable to estimate any required emissions reductions at this time.

Nuclear Operations

Property Insurance

DTE Electric maintains property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. 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 $1.5 billion in primary coverage and $1.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion, subject to a $1 million deductible. The total limit for property damage for non-nuclear events is $2 billion and an aggregate of $327 million of coverage for extra expenses over a two-year period.

31

DTE Energy Company

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

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 $35 million per event if the loss associated with any one event at any nuclear plant should exceed the accumulated funds available to NEIL.

Public Liability Insurance

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

Nuclear Fuel Disposal Costs

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

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement agreement, including extensions, provides for a claims process and payment of delay-related costs experienced by DTE Electric through 2016. DTE Electric has begun the claims process and claims are being settled and paid on a timely basis. The settlement proceeds reduce the cost of the dry cask storage facility assets and provide reimbursement for related operating expenses. The federal government continues to maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by DTE Electric ratepayers to the federal waste fund await future governmental action.

In February 2013, the U.S. Court of Appeals for the District of Columbia (COA) granted a motion to reopen the fee adequacy litigation to review the DOE's latest fee adequacy report which was released in January 2013. In November 2013, the COA issued a decision ordering the DOE to submit a proposal to Congress to reduce the nuclear waste fee to zero until the DOE enacts an alternative nuclear waste management plan. In January 2014, the DOE submitted such a proposal to Congress that was scheduled to take effect in 90 legislative calendar days, absent legislative action to the contrary. Simultaneously, the DOE filed a petition for rehearing of the November 2013 decision with the COA. In March 2014, the COA denied DOE's petition for rehearing. The 1 mill per kWh fee was reduced to zero effective May 16, 2014.

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, 2014 is approximately $1.1 billion. Payment under these guarantees is considered remote.

32

DTE Energy Company

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

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, 2014 is approximately $129 million. Payment under these guarantees is considered remote.

Other Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. The Company’s guarantees are not individually material with maximum potential payments totaling $60 million at June 30, 2014. Payment under these guarantees is considered remote.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of June 30, 2014, the Company had approximately $46 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

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

Purchase Commitments

As of June 30, 2014, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments, renewable energy contracts and energy trading contracts. The Company estimates that these commitments will be approximately $8.6 billion from 2014 through 2051.

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

Bankruptcies

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

33

DTE Energy Company

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

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 5 and 7 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 12 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Three Months Ended June 30	(In millions)
Service cost	$	22		$	25		$	9		$	12
Interest cost	52			47			22			21
Expected return on plan assets	(68		)	(66		)	(30		)	(27		)
Amortization of:
Net actuarial loss	38			50			6			15
Prior service credit	—			—			(36		)	(36		)
Net periodic benefit cost (credit)	$	44		$	56		$	(29	)	$	(15	)

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Six Months Ended June 30	(In millions)
Service cost	$	43		$	49		$	18		$	28
Interest cost	105			95			45			45
Expected return on plan assets	(136		)	(133		)	(61		)	(54		)
Amortization of:
Net actuarial loss	76			101			11			32
Prior service credit	—			—			(72		)	(59		)
Net periodic benefit cost (credit)	$	88		$	112		$	(59	)	$	(8	)

Pension and Other Postretirement Contributions

During the first six months of 2014, the Company contributed $101 million to its pension plans. At the discretion of management, and depending upon financial market conditions, the Company may make up to an additional $90 million contribution to its pension plans in 2014.

At the discretion of management, the Company may make up to a $145 million contribution to its other postretirement benefit plans in 2014.

34

DTE Energy Company

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

NOTE 13 — STOCK-BASED COMPENSATION

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In millions)
Stock-based compensation expense	$	16	$	35	$	50	$	63
Tax benefit	$	6	$	14	$	19	$	25
Stock-based compensation cost capitalized in property, plant and equipment	$	2	$	2	$	7	$	4

Stock Options

The following table summarizes our stock option activity for the six months ended June 30, 2014:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at January 1, 2014	723,697		$	42.60
Exercised	(204,108	)	$	41.54
Forfeited or expired	(10,730	)	$	39.41
Options outstanding and exercisable at June 30, 2014	508,859		$	43.10	$	17

As of June 30, 2014, the weighted average remaining contractual life for the exercisable shares is 3.74 years. As of June 30, 2014, all options were vested.

The intrinsic value of options exercised for the six months ended June 30, 2014 and 2013 was $6 million and $10 million, respectively. No option expense was recognized for the six months ended June 30, 2014 and 2013, respectively.

Restricted Stock Awards

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2014:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2014	492,329		$	53.76
Grants	156,390		$	69.95
Forfeitures	(13,764	)	$	62.25
Vested and issued	(216,103	)	$	47.58
Balance at June 30, 2014	418,852		$	62.71

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. Awards granted in 2014 were primarily deemed to be equity awards. The stock price and number of probable shares attributable to market conditions for such equity awards are fair valued only at the grant date. Performance shares awarded prior to 2014 are liability awards and are remeasured to fair value at each reporting period.

35

DTE Energy Company

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

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2014:

	Performance Shares		Weighted Average Grant Date Fair Value
Balance at January 1, 2014	1,608,789		$	—
Grants	532,585		$	69.16
Forfeitures	(27,390	)	$	69.10
Payouts	(571,177	)	$	—
Balance at June 30, 2014	1,542,807		$	69.17

Unrecognized Compensation Costs

As of June 30 2014, there was $82 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 1.48 years.

NOTE 14 — 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 are 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.

36

DTE Energy Company

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014		2013
	(In millions)
Inter-segment Revenues
Electric	$	7		$	7		$	14	$	13
Gas	2			1			4		2
Gas Storage and Pipelines	7			2			8		4
Power and Industrial Projects	176			185			382		390
Energy Trading	7			12			16		23
Corporate and Other	(1		)	(7		)	1		(15		)
	$	198		$	200		$	425	$	417

Financial data of the business segments follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In millions)
Operating Revenues
Electric	$	1,279		$	1,265		$	2,691		$	2,484
Gas	229			248			1,033			852
Gas Storage and Pipelines	45			31			97			58
Power and Industrial Projects	523			429			1,098			919
Energy Trading	819			451			2,133			844
Corporate & Other	1			1			1			1
Reconciliation & Eliminations	(198		)	(200		)	(425		)	(417		)
Total	$	2,698		$	2,225		$	6,628		$	4,741

Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	129		$	89		$	265		$	204
Gas	(4		)	8			125			104
Gas Storage and Pipelines	18			16			39			33
Power and Industrial Projects	13			7			28			19
Energy Trading	(14		)	(2		)	28			5
Corporate & Other	(18		)	(13		)	(35		)	(26		)
Net Income Attributable to DTE Energy	$	124		$	105		$	450		$	339

37

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 2014 was $124 million, or $0.70 per diluted share, compared to net income attributable to DTE Energy of $105 million, or $0.60 per diluted share, in the second quarter of 2013. Net income attributable to DTE Energy in the six months ended June 30, 2014 was $450 million, or $2.54 per diluted share, compared to net income attributable to DTE Energy of $339 million, or $1.94 per diluted share, in the six months ended June 30, 2013. The increase in net income in the second quarter is primarily due to higher earnings in the Electric segment, partially offset by lower earnings in the Gas and Energy Trading segments. The increase in net income for the six months ended June 30, 2014 is primarily due to higher earnings in the Electric, Gas and Energy Trading segments.

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

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

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

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

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

CAPITAL INVESTMENTS

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

DTE Gas's capital investments over the 2014-2018 period are estimated at $700 million for base infrastructure and $500 million for gas main renewal and meter move out and pipeline integrity programs. In April 2013, the MPSC issued an order approving an infrastructure recovery mechanism (IRM) for DTE Gas 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, acid gases, particulate matter and mercury emissions. To comply with these requirements, DTE Electric spent approximately $2 billion through 2013. It is estimated that DTE Electric will make capital expenditures of approximately $280 million in 2014 and up to approximately $1.2 billion of additional capital expenditures through 2021 based on current regulations.

Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA. The EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs). EPA regulation of GHGs requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. In June 2012, the EPA proposed new source performance standards for carbon dioxide emissions from new fossil-fueled power plants. These new source performance standards were re-proposed on September 20, 2013, under a presidential directive issued on June 25, 2013. Under the same presidential directive, the EPA proposed performance standards for carbon dioxide emissions from existing, reconstructed and modified plants on June 2, 2014 and plans to issue a final standard by July 2015. DTE Energy is an active participant in working with the EPA and other stakeholders to shape the final performance standards for new and existing power plants. The 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 credits 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 as authorized by the MPSC. Increased costs for energy produced from traditional coal-based sources could also increase the economic viability of energy produced from renewable and/or nuclear sources, from energy efficiency initiatives, and from the potential development of market-based trading of carbon offsets which could provide new business opportunities for our utility and non-utility segments. A June 23, 2014 U.S. Supreme Court decision on the EPA’s authority to regulate greenhouse gas emissions under permitting programs of the Clean Air Act is expected to have little effect on DTE Energy since the Supreme Court's decision upholds the EPA’s authority to regulate GHGs at sources that are already subject to permitting due to emissions of conventional pollutants. In addition, the Supreme Court's ruling does not affect the EPA’s current proposed carbon performance standards at new or existing power plants. At the present time, it is not possible to quantify the financial impacts of these climate related legislative or regulatory initiatives on DTE Energy or its customers.

See Note 11 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:

• electric and gas customer satisfaction;

• electric reliability;

• rate competitiveness and affordability;

• regulatory stability and investment recovery for our utilities;

39

• growth of our utility asset base;

• employee engagement;

• cost structure optimization across all business segments;

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

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

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

RESULTS OF OPERATIONS

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In millions)
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	129		$	89		$	265		$	204
Gas	(4		)	8			125			104
Gas Storage and Pipelines	18			16			39			33
Power and Industrial Projects	13			7			28			19
Energy Trading	(14		)	(2		)	28			5
Corporate and Other	(18		)	(13		)	(35		)	(26		)
Net Income Attributable to DTE Energy Company	$	124		$	105		$	450		$	339

ELECTRIC

Our Electric segment consists principally of DTE Electric.

Electric results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In millions)
Operating Revenues	$	1,279		$	1,265		$	2,691		$	2,484
Fuel and Purchased Power	400			435			898			807
Gross Margin	879			830			1,793			1,677
Operation and Maintenance	328			343			671			674
Depreciation and Amortization	230			221			460			435
Taxes Other Than Income	65			64			136			134
Asset (Gains) and Losses, Reserves and Impairments, Net	(1		)	1			(1		)	—
Operating Income	257			201			527			434
Other (Income) and Deductions	51			65			109			122
Income Tax Expense	77			47			153			108
Net Income Attributable to DTE Energy Company	$	129		$	89		$	265		$	204
Operating Income as a Percent of Operating Revenues	20		%	16		%	20		%	17		%

Gross margin increased $49 million and $116 million in the three and six months ended June 30, 2014, respectively. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements 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)
Amortization of refundable revenue decoupling/deferred gain	$	32		$	63
Base sales, inclusive of weather effect	10			26
Securitization bond and tax surcharge	—			8
Renewable energy program	6			11
Low income energy assistance surcharge	6			13
Regulatory mechanisms and other	(5		)	(5		)
Increase in gross margin	$	49		$	116

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2014	2013	2014	2013
	(In thousands of MWh)
Electric Sales
Residential	3,452	3,345	7,430	7,199
Commercial	4,168	4,158	8,216	8,081
Industrial	2,554	2,675	5,055	5,111
Other	171	216	376	468
	10,345	10,394	21,077	20,859
Interconnection sales (a)	479	792	1,097	1,565
Total Electric Sales	10,824	11,186	22,174	22,424
Electric Deliveries
Retail and Wholesale	10,345	10,394	21,077	20,859
Electric Customer Choice, including self generators (b)	1,237	1,287	2,504	2,547
Total Electric Sales and Deliveries	11,582	11,681	23,581	23,406

______________________________

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

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

Operation and maintenance expense decreased $15 million and $3 million in the three and six months ended June 30, 2014, respectively. The decrease in the second quarter was due primarily to lower employee benefit expenses of $24 million and $12 million of reinvestment expenses in 2013, partially offset by higher storm restoration expenses of $9 million, increased low income energy assistance of $7 million and higher power plant generation expenses for planned outages of $5 million. The decrease in the six-month period was primarily due to lower employee benefit expenses of $46 million and $12 million of reinvestment expenses in 2013, partially offset by higher power plant generation expenses of $35 million, increased low income energy assistance of $13 million, higher storm restoration expenses of $4 million and higher energy optimization and renewable energy expenses of $4 million.

Depreciation and amortization expense increased $9 million and $25 million in the three and six months ended June 30, 2014, respectively. The increase in the second quarter was due to higher amortization of regulatory assets of $5 million, primarily related to Securitization, and $4 million of increased expense due to a higher depreciable base. The increase in the six-month period was due to higher amortization of regulatory assets of $16 million, primarily related to Securitization, and $9 million of increased expense due to a higher depreciable base.

Other (income) and deductions were lower by $14 million and $13 million in the three and six months ended June 30, 2014, respectively. The decrease in the second quarter was due primarily to lower interest expense and higher investment earnings, while the decrease in the six-month period was due primarily to lower interest expense.

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

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

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,
	2014			2013			2014			2013
	(In millions)
Operating Revenues	$	229		$	248		$	1,033		$	852
Cost of Gas	69			80			508			379
Gross Margin	160			168			525			473
Operation and Maintenance	115			105			225			211
Depreciation and Amortization	23			24			48			47
Taxes Other Than Income	16			15			33			31
Operating Income	6			24			219			184
Other (Income) and Deductions	11			11			23			23
Income Tax Expense (Benefit)	(1		)	5			71			57
Net Income (Loss) Attributable to DTE Energy Company	$	(4	)	$	8		$	125		$	104
Operating Income as a Percent of Operating Revenues	3		%	10		%	21		%	22		%

Gross margin decreased $8 million and increased $52 million in the three and six months ended June 30, 2014, respectively. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations.

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

	Three Months			Six Months
	(In millions)
Weather	$	(5	)	$	41
Midstream storage and transportation services	(3		)	13
Energy optimization revenue	(2		)	(8		)
Other	2			6
Increase (decrease) in gross margin	$	(8	)	$	52

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2014	2013	2014	2013
Gas Markets (in Bcf)
Gas sales	17	18	88	76
End user transportation	32	32	94	87
	49	50	182	163
Intermediate transportation	75	76	174	152
	124	126	356	315

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Operation and maintenance expense increased $10 million and $14 million in the three and six months ended June 30, 2014, respectively. The increase in the second quarter was due primarily to the timing of gas operations expenses of $8 million, increased uncollectible expenses of $3 million, higher corporate administrative expenses of $2 million and $1 million of reinvestment expenses, partially offset by lower employee benefit expenses of $5 million. The increase in the six-month period was primarily due to higher weather-related gas operations expenses of $20 million, increased uncollectible expenses of $4 million, higher corporate administrative expenses of $3 million and $1 million of reinvestment expenses, partially offset by lower employee benefit expenses of $8 million and lower energy optimization expenses of $7 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 capital investments will result in earnings growth. Looking forward, additional factors may impact earnings such as weather, the outcome of regulatory proceedings, benefit plan design changes, and investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

GAS STORAGE AND PIPELINES

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

Gas Storage and Pipelines results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In millions)
Operating Revenues	$	45		$	31		$	97		$	58
Operation and Maintenance	10			7			21			12
Depreciation and Amortization	9			4			16			8
Taxes Other Than Income	1			1			2			2
Operating Income	25			19			58			36
Other (Income) and Deductions	(6		)	(8		)	(8		)	(19		)
Income Tax Expense	12			10			26			21
Net Income Attributable to DTE Energy Company	19			17			40			34
Noncontrolling interest	1			1			1			1
Net Income Attributable to DTE Energy	$	18		$	16		$	39		$	33

Operating revenues increased $14 million and $39 million in the three and six months ended June 30, 2014, respectively. The increases were due primarily to higher volumes on the Bluestone pipeline, additional segments placed in service in the Susquehanna gathering system and higher storage revenue.

Operation and maintenance expenses increased $3 million and $9 million in the three and six months ended June 30, 2014, respectively. The increases were due primarily to the operation of the Bluestone and Susquehanna projects.

Depreciation and amortization expenses increased $5 million and $8 million in the three and six months ended June 30, 2014, respectively. The increases were due to the operation of the Bluestone and Susquehanna projects.

Other (income) and deductions decreased by $2 million and $11 million in the three and six months ended June 30, 2014, respectively. The decreases were due to lower earnings from a pipeline investment and higher intercompany interest expense.

Outlook — Our Gas Storage and Pipelines business expects to maintain its steady growth by developing an asset portfolio with multiple growth platforms through investment in new projects and expansions. We will continue to look for additional investment opportunities and other storage and pipeline projects at favorable prices. Millennium Pipeline completed its Phase Two expansion which was placed in service at the end of March 2014. We have begun to expand the capacity of Bluestone, a 44-mile lateral pipeline in Susquehanna County, Pennsylvania and Broome County, New York, by constructing additional compression facilities, meter upgrades, and other initiatives to accommodate increased shipper demand. Through our agreement with Southwestern Energy Services Company and affiliates, we believe Bluestone lateral and Susquehanna gathering system are strategically positioned for future growth of the Marcellus shale. Progress continues on preliminary development activities on the proposed Nexus pipeline. The Nexus pipeline will serve as a transportation path for natural gas from the Utica shale in Ohio to Michigan and Ontario. We are planning to have a partnership interest in the pipeline.

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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,
	2014			2013			2014			2013
	(In millions)
Operating Revenues	$	523		$	429		$	1,098		$	919
Operation and Maintenance	528			422			1,104			903
Depreciation and Amortization	19			17			37			35
Taxes other than Income	3			3			8			8
Asset (Gains) and Losses, Reserves and Impairments, Net	(6		)	4			(7		)	1
Operating Income (Loss)	(21		)	(17		)	(44		)	(28		)
Other (Income) and Deductions	(8		)	(16		)	(21		)	(25		)
Income Taxes
Expense	(6		)	(1		)	(10		)	(1		)
Production Tax Credits	(21		)	(8		)	(43		)	(23		)
	(27		)	(9		)	(53		)	(24		)
Net Income	14			8			30			21
Noncontrolling interest	1			1			2			2
Net Income Attributable to DTE Energy Company	$	13		$	7		$	28		$	19

Operating revenues increased $94 million and $179 million in the three months and six months ended June 30, 2014, respectively. The increase in the second quarter was due primarily to a $100 million increase associated with higher volumes from REF projects, and an $8 million increase associated with start-up of a biomass-fired power project, partially offset by a $13 million decrease from lower coal prices associated with the steel business. The increase in the six-month period was due primarily to a $206 million increase associated with higher volumes from REF projects, and a $12 million increase associated with start-up of a biomass-fired power project, partially offset by a $38 million decrease from lower coal prices associated with the steel business.

Operation and maintenance expense increased $106 million and $201 million in the three months and six months ended June 30, 2014, respectively. The increase in the second quarter was due primarily to a $102 million increase associated with higher volumes from REF projects, a $9 million increase for higher maintenance expenses associated with the steel business, and an $8 million increase associated with start-up of a biomass-fired power project, partially offset by a $13 million decrease from lower coal prices associated with the steel business. The increase in the six-month period was due primarily to a $210 million increase associated with higher volumes from REF projects, a $16 million increase for higher maintenance expenses associated with the steel business, and a $14 million increase associated with start-up of a biomass-fired power project, partially offset by a $38 million decrease from lower coal prices associated with the steel business.

Asset (gains) losses, reserves and impairments, net were higher by $10 million and $8 million in the three and six months ended June 30, 2014, respectively. The increases were due primarily to a gain associated with a sale of an on-site project in 2014 and an asset impairment recorded in the prior year.

Other (income) and deductions decreased by $8 million and $4 million in the three and six months ended June 30, 2014, respectively. The decrease in the second quarter was due primarily to $4 million in lower volumes of refined coal produced at sites with investors and a $5 million decrease related to lower equity earnings at various projects. The decrease in the six-month period was due primarily to $3 million in lower volumes of refined coal produced at sites with investors.

Production tax credits increased by $13 million and $20 million in the three and six months ended June 30, 2014, respectively. The increases were due primarily due to tax credits earned from REF projects.

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

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

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

ENERGY TRADING

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

Energy Trading results are discussed below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014		2013
	(In millions)
Operating Revenues	$	819		$	451		$	2,133	$	844
Fuel, Purchased Power and Gas	823			432			2,049		789
Gross Margin	(4		)	19			84		55
Operation and Maintenance	16			19			32		40
Depreciation and Amortization	—			1			—		1
Taxes Other Than Income	2			—			3		2
Operating Income (Loss)	(22		)	(1		)	49		12
Other (Income) and Deductions	2			2			4		4
Income Tax Expense (Benefit)	(10		)	(1		)	17		3
Net Income (Loss) Attributable to DTE Energy Company	$	(14	)	$	(2	)	$	28	$	5

Operating revenues and Fuel, purchased power and gas were impacted by an increase in gas prices and volumes, primarily in our gas structured and gas transportation strategies for both the three and six months ended June 30, 2014.

Gross margin decreased $23 million and increased $29 million for the three and six months ended June 30, 2014, respectively. The second quarter decrease in gross margin of $23 million represents a $7 million decrease in realized margins and a $16 million decrease in unrealized margins. The $7 million decrease in realized margins is due to $23 million of unfavorable results, primarily in our power trading and power full requirements strategies, offset by $16 million of favorable results, primarily in our gas structured strategy. The $16 million decrease in unrealized margins is due to $29 million of unfavorable results, primarily in our gas structured and power trading strategies, offset by $13 million of favorable results, primarily in our power full requirements strategy.

The $29 million increase in gross margin for the six months ended June 30, 2014 represents a $43 million increase in realized margins and a $14 million decrease in unrealized margins. The $43 million increase in realized margins is due to $127 million of favorable results, primarily in our gas structured and gas transportation strategies, offset by $84 million of unfavorable results, primarily in our power full requirements strategy. The $14 million decrease in unrealized margins is due to $44 million of unfavorable results, primarily in our gas structured, power trading, and gas storage strategies, offset by $30 million of favorable results, primarily in our gas trading and power full requirements strategies.

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In the first quarter of 2014, extreme weather conditions occurred in the Midwest and Northeast gas and power markets we serve. Consequently, this led to favorable results in our gas asset optimization strategies due to higher gas prices and volumes which were partially offset by realized losses from our power full requirements strategy due to higher than expected loads, energy prices, and ancillary charges to serve our customers.

Natural gas structured transactions typically involve a physical purchase or sale of natural gas in the future and/or natural gas basis financial instruments which are derivatives and a related non-derivative pipeline transportation contract. These gas structured transactions can result in significant earnings volatility as the derivative components are marked-to-market without revaluing the related non-derivative contracts. During the fourth quarter of 2013, we saw significant increases in gas prices which led to the volatility in the accounting earnings due to the physical component being marked-to-market without an offsetting mark on the transportation component. Included in the $127 million of favorable results for the six months ended June 30, 2014 in our gas strategies is $58 million of timing related losses recognized in the fourth quarter of 2013 that reversed primarily during the first three months of 2014 as the underlying contracts were settled.

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

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

See Notes 4 and 5 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. The net loss of $18 million and $35 million in the three and six months ended June 30, 2014, respectively, represents an increase of $5 million and $9 million, respectively, from the losses of $13 million and $26 million in the comparable 2013 periods. The increased loss in the six month period was due primarily to higher deferred tax expense related to New York state income tax reform enacted on March 31, 2014.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and natural gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. We expect that cash from operations in 2014 will be approximately $1.6 billion, or approximately $500 million lower than 2013, due primarily to lower surcharge collections and higher cash contributions to employee benefit plans. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2014 of approximately $2.3 billion. We plan to seek regulatory approval to include utility capital expenditures in our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

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	Six Months Ended June 30,
	2014			2013
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	453		$	342
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	562			527
Nuclear fuel amortization	19			17
Allowance for equity funds used during construction	(11		)	(6		)
Deferred income taxes	196			123
Asset (gains) and losses, reserves and impairments, net	(7		)	—
Working capital and other	(136		)	264
Net cash from operating activities	1,076			1,267
Investing activities:
Plant and equipment expenditures — utility	(924		)	(708		)
Plant and equipment expenditures — non-utility	(156		)	(197		)
Proceeds from sale of assets	31			15
Other	(18		)	(21		)
Net cash used for investing activities	(1,067		)	(911		)
Financing activities:
Issuance of long-term debt, net of issuance costs	595			371
Redemption of long-term debt	(664		)	(515		)
Short-term borrowings, net	380			(24		)
Issuance of common stock	—			19
Repurchase of common stock	(52		)	—
Dividends on common stock and other	(245		)	(226		)
Net cash from (used for) financing activities	14			(375		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	23		$	(19	)

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, 2014 was $191 million lower than the comparable 2013 period. The operating cash flow comparison reflects higher cash expenditures for working capital items partially offset by higher net income after adjusting for non-cash and non-operating items (primarily depreciation, depletion and amortization, and deferred income taxes).

Cash used for Investing Activities

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

Capital spending within the utility 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.

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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 $156 million in 2014 due primarily to increased capital expenditures by our utility businesses, partially offset by lower capital expenditures by our non-utility businesses and higher proceeds from sale of assets.

Cash from (used for) Financing Activities

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

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

Net cash from financing activities was higher by $389 million in 2014 due primarily to increased short-term borrowings and issuances of long-term debt, partially offset by higher redemptions of long-term debt, repurchases of common stock and higher dividends on common stock.

Outlook

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

We may be impacted by the timing of collection or refund of 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 $200 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. In July 2014, DTE Electric issued $700 million of mortgage bonds. Proceeds will be used for redemption of DTE Electric long-term debt, for the repayment of short-term borrowings and for general corporate purposes.

DTE Energy has approximately $1.4 billion of available liquidity at June 30, 2014, consisting of cash and amounts available under unsecured revolving credit agreements.

During the first six months of 2014, we contributed $101 million to our pension plans. At the discretion of management, and depending upon financial market conditions, we may make up to an additional $90 million contribution to our pension plans in 2014. At the discretion of management, we may make up to a $145 million contribution to our other postretirement benefit plans in 2014.

48

Various subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to require that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be required to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily natural gas, power and coal) and the provisions and maturities of the underlying transactions. As of June 30, 2014, DTE Energy's contractual obligation to post collateral in the form of cash or letter of credit in the event of a downgrade to below investment grade, under both hard trigger and soft trigger provisions, was approximately $331 million.

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

See Notes 7, 9, 10 and 12 of the Notes to Consolidated Financial Statements.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 3 of the Notes to Consolidated Financial Statements.

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 4 and 5 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 MTM risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, the Company records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or natural gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).

The Company has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value hierarchy, see Note 4 of the Notes to Consolidated Financial Statements.

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The following tables provide details on changes in our MTM net asset (or liability) position for the six months ended June 30, 2014:

	Total
	(In millions)
MTM at January 1, 2014	$	(112	)
Reclassify to realized upon settlement	(81		)
Changes in fair value recorded to income	122
Amounts recorded to unrealized income	41
Changes in fair value recorded in regulatory liabilities	11
Change in collateral held by (for) others	11
Option premiums paid (received) and other	(4		)
MTM at June 30, 2014	$	(53	)

The table below shows the maturity of our MTM positions:

Source of Fair Value	2014			2015			2016			2017  and  Beyond			Total Fair Value
	(In millions)
Level 1	$	(7	)	$	4		$	1		$	—		$	(2	)
Level 2	19			(18		)	(13		)	(1		)	(13		)
Level 3	(21		)	(19		)	(1		)	1			(40		)
MTM before collateral adjustments	$	(9	)	$	(33	)	$	(13	)	$	—		(55		)
Collateral adjustments													2
MTM at June 30, 2014													$	(53	)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market Price Risk

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

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

Our Power and Industrial Projects business segment is subject to electricity, natural gas and coal price risk. The Company manages its exposure through the use of long-term contracts.

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

Credit Risk

Bankruptcies

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

Other

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

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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, 2014:

	Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure
	(In millions)
Investment Grade (a)
A− and Greater	$	163	$	(5	)	$	158
BBB+ and BBB	208		—			208
BBB−	56		—			56
Total Investment Grade	427		(5		)	422
Non-investment grade (b)	2		—			2
Internally Rated — investment grade (c)	169		(1		)	168
Internally Rated — non-investment grade (d)	21		(5		)	16
Total	$	619	$	(11	)	$	608

_______________________________________

(a) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors Service (Moody’s) or 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 16% of the total gross credit exposure.

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

(c) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 12% 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 3% 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, 2014, we had a floating rate debt-to-total debt ratio of approximately 6.4% (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 November 2017.

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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, 2014 and 2013 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of June 30, 2014 and 2013:

	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of June 30,						As of June 30,
Activity	2014			2013			2014			2013			Change in the Fair Value of
	(In millions)
Coal contracts	$	—		$	—		$	—		$	—		Commodity contracts
Natural gas contracts	$	(21	)	$	(12	)	$	21		$	12		Commodity contracts
Electricity contracts	$	10		$	6		$	(9	)	$	(6	)	Commodity contracts
Interest rate risk	$	(300	)	$	(264	)	$	317		$	279		Long-term debt
Foreign currency exchange risk	$	—		$	—		$	—		$	—		Forward contracts
Discount rates	$	—		$	—		$	—		$	—		Commodity contracts

For further discussion of market risk, see Note 5 of the Notes to Consolidated Financial Statements.

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, 2014, which is the end of the period covered by this report. Based on this evaluation, the Company's CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and (ii) is accumulated and communicated to the Company's management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) 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, 2014 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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Part II — Other Information

Item 1. Legal Proceedings

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

In August 2010, the U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. On March 28, 2013, the Court of Appeals remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements. On September 3, 2013, the EPA caused to be filed a motion seeking leave to amend their complaint regarding the June 2010 NOV/FOV adding additional claims related to outage work performed at the Trenton Channel and Belle River power plants as well as additional claims related to work performed at the Monroe Power Plant. In addition, the Sierra Club caused to be filed a motion to add a claim regarding the River Rouge Power Plant. On March 3, 2014, the U.S. District Court judge granted again DTE Energy's motion for summary judgment dismissing the civil case related to Monroe Unit 2. On April 3, 2014, the U.S. District Court judge granted motions filed by the EPA and the Sierra Club to amend their New Source Review complaint adding additional claims for Monroe Units 1, 2 and 3, Belle River Units 1 and 2, Trenton Channel Unit 9 and River Rouge Unit 3. On June 30, 2014, the EPA filed a motion requesting certification for appeal of the March 3, 2014 summary judgment decision.

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

In March 2013, the Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499 6-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the court enjoin DTE Energy and DTE Electric from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. In December 2013, a U.S. District Court judge issued an order dismissing, without prejudice, the plaintiff's complaint allowing them to file an amended complaint by January 17, 2014. The order dismissing the complaint resulted from a considerable number of plaintiff's claims being time barred based on the statute of limitations. On January 17, 2014, the plaintiffs filed an amended complaint for the period January 13, 2008 - June 30, 2012, reducing the total number of 6-minute periods from 1,499 to 1,139. DTE Energy and DTE Electric filed an answer to the amended complaint on March 11, 2014. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

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

For additional discussion on legal matters, see Notes 7 and 11 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 2013 Form 10-K. Although we have tried to identify and discuss key risk factors, others could emerge in the future.

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

The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act of 1934 for the quarter ended June 30, 2014:

	Number of Shares Purchased (a)	Average Price Paid per Share (a)		Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Average Price Paid per Share	Maximum Dollar Value that May Yet Be Purchased Under the Plans or Programs
04/01/2014 — 04/30/2014	—	$	—	—	—	—
05/01/2014 — 05/31/2014	30,680	$	75.77	—	—	—
06/01/2014 — 06/30/2014	17,501	$	75.83	—	—	—
Total	48,181			—

_______________________________________

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

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Item 6. Exhibits

	(i) Exhibits filed herewith:
4-284	Supplemental Indenture, dated as of May 1, 2014, between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (2014 Series C)
10-90	Form of Change-In-Control Severance Agreement dated as of July 1, 2014, between DTE Energy Company and each of Donna M. England and Lisa A. Muschong
10-91	Form of Change-In-Control Severance Agreement dated as of July 1, 2014, between DTE Energy Company and each of Naif A. Khouri, David Ruud and Mark W. Stiers
12-58	Computation of Ratio of Earnings to Fixed Charges
31-91	Chief Executive Officer Section 302 Form 10-Q Certification of Periodic Report
31-92	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 incorporated herein by reference:
4-285	Supplemental Indenture, dated as of June 1, 2014, to the Mortgage and Deed of Trust dated as of October 1, 1924, between DTE Electric Company and The Bank of New York Mellon, N.A., as successor trustee (Exhibit 4-282 to DTE Electric Form 10-Q for the quarter ended June 30, 2014). (2014 Series A and B)
4-286	Supplemental Indenture, dated as of July 1, 2014, to the Mortgage and Deed of Trust dated as of October 1, 1924, between DTE Electric Company and The Bank of New York Mellon, N.A., as successor trustee (Exhibit 4-283 to DTE Electric Form 10-Q for the quarter ended June 30, 2014). (2014 Series D and E)

	(iii) Exhibits furnished herewith:
32-91	Chief Executive Officer Section 906 Form 10-Q Certification of Periodic Report
32-92	Chief Financial Officer Section 906 Form 10-Q Certification of Periodic Report

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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 25, 2014	By	/s/  DONNA M. ENGLAND
		Donna M. England Chief Accounting Officer (Principal Accounting Officer)

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EX-4.284

Exhibit 4-284

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

__________________________

SUPPLEMENTAL INDENTURE
DATED AS OF MAY 1, 2014

__________________________

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

PROVIDING FOR

2014 SERIES C 3.50% SENIOR NOTES DUE 2024

SUPPLEMENTAL INDENTURE, dated as of the 1st day of May, 2014, between DTE ENERGY COMPANY, a corporation organized and existing under the laws of the State of Michigan (the “Company”), and The Bank of New York Mellon Trust Company, N.A., as successor trustee (the “Trustee”);

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

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

WHEREAS, the Company, in the exercise of the power and authority conferred upon and reserved to it under the provisions of the Original Indenture, including Section 901 thereof, and pursuant to appropriate resolutions of the Board of Directors, has duly determined to make, execute and deliver to the Trustee this Supplemental Indenture to the Original Indenture as permitted by Section 201 and Section 301 of the Original Indenture in order to establish the form or terms of, and to provide for the creation and issue of, a series of its debt securities under the Original Indenture, which shall be known as the “2014 Series C 3.50% Senior Notes due 2024”; and

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

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

article 1
DEFINITIONS AND OTHER
PROVISIONS OF GENERAL APPLICATION

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

“Business Day” means any day other than a Saturday or Sunday or a day on which commercial banks in the state of New York or the state of Michigan are required or authorized by law or executive order to be closed.

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

ARTICLE 2
TITLE AND TERMS OF THE SECURITIES

SECTION 201.Title of the Securities; Stated Maturity. This Supplemental Indenture hereby establishes a series of Securities, which shall be known as the Company's “2014 Series C 3.50% Senior Notes due 2024” (the “Notes”). The Stated Maturity on which the principal of the Notes shall be due and payable will be June 1, 2024.

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

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

SECTION 204.Amount and Denominations; DTC. (a)  The aggregate principal amount of the Notes that may be issued under this Supplemental Indenture is limited initially to $350,000,000 (except as provided in Section 301(2) of the Original Indenture); provided that the Company may, without the consent of the Holders of the Outstanding Notes, “reopen” the Notes so as to increase the aggregate principal amount of the Notes Outstanding in compliance with the procedures set forth in the Original Indenture, including Section 301 and Section 303 thereof, so long as any such additional Notes have the same tenor and terms (including, without limitation, rights to receive accrued and unpaid interest) as the Notes then Outstanding. No additional Notes may be issued if an Event of Default has occurred. The Notes shall be issuable only in fully registered form and, as permitted by Section 301 and Section 302 of the Original Indenture, in denominations of $1,000 and integral multiples thereof. The Notes will initially be issued in global form (the “Global Notes”) under a book-entry system, registered in the name of The Depository Trust Company, as depository (“DTC”), or its nominee, which is hereby designated as “Depositary” under the Indenture.

(b)Further to Section 305 of the Original Indenture, any Global Note shall be exchangeable for Notes registered in the name of, and a transfer of a Global Note may be registered to, any Person other than the Depositary for such Note or its nominee only if (i) such Depositary notifies the Company that it is unwilling or unable to continue as Depositary for such Global Note or if at any time such Depositary ceases to be a clearing agency registered under the Exchange Act, and, in either such case, the Company does not appoint a successor Depositary within 90 days thereafter, (ii) the Company executes and delivers to the Trustee a Company Order that such Global Note shall be so exchangeable and the transfer thereof so registrable or (iii) there shall have occurred and be continuing an Event of Default or an event which, with the giving of notice or lapse of time, or both, would constitute an Event of Default with respect to the Notes. Upon the occurrence in respect of a Global Note of any or more of the conditions specified in clause (i), (ii) or (iii) of the preceding sentence, such Global Note may be exchanged for Notes registered in the name of, and the transfer of such Global Note may be registered to, such Persons (including Persons other than the Depositary and its nominees) as such Depositary, in the case of an exchange, and the Company, in the case of a transfer, shall direct.

SECTION 205.Terms of the Notes.

(a)    The Notes shall bear interest at the rate of 3.50% per annum on the principal amount thereof from May 13, 2014, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, until the principal of the Notes becomes due and payable, and on any overdue principal and premium and (to the extent that payment of such interest is enforceable under applicable law) on any overdue installment of interest at the same rate per annum during such overdue period. Interest on the Notes will be payable semiannually in arrears on June 1 and December 1 of each year (each such date, an “Interest Payment Date”), commencing December 1, 2014. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year.

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

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

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

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

ARTICLE 3
MISCELLANEOUS PROVISIONS

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

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

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

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

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

DTE ENERGY COMPANY

By:/s/ Mark C. Rolling

Name:    Mark C. Rolling

Title:     Vice President and Treasurer

ATTEST:

By:/s/ Lisa A. Muschong

Name:    Lisa A. Muschong

Title:     Corporate Secretary

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

By:/s/ Richard Tarnas

Name:    Richard Tarnas

Title:     Vice President

EXHIBIT A

FORM OF NOTE

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

CUSIP NO. ___________                              $__________

NO. : ______

DTE ENERGY COMPANY
2014 SERIES C 3.50% SENIOR NOTES DUE 2024

DTE ENERGY COMPANY, a corporation duly organized and existing under the laws of the State of Michigan (herein referred to as the “Company”, which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to CEDE & CO., or registered assigns, the principal sum of $__________ on June 1, 2024 (“Stated Maturity” with respect to the principal of this Note), unless previously redeemed, and to pay interest at the rate of 3.50% per annum on said principal sum from May 13, 2014, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, until the principal of this Note becomes due and payable, and on any overdue principal and premium and (to the extent that payment of such interest is enforceable under applicable law) on any overdue installment of interest at the same rate per annum during such overdue period. Interest on this Note will be payable semiannually in arrears on June 1 and December 1 of each year (each such date, an “Interest Payment Date”), commencing December 1, 2014. The amount of interest payable for any period shall be computed on the basis of twelve 30-day months and a 360-day year.

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

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

This Note is one of a duly authorized series of Securities of the Company, designated as the “2014 Series C 3.50% Senior Notes due 2024” (the “Notes”), initially limited to an aggregate principal amount of $350,000,000 (except for Notes authenticated and delivered upon transfer of, or in exchange for, or in lieu of other Notes, and except as further provided in the Indenture), all issued or to be issued under and pursuant to an Amended and Restated Indenture, dated as of April 9, 2001, as supplemented through and including the Supplemental Indenture dated as of May 1, 2014 (together, as amended, supplemented or modified, the “Indenture”), duly executed and delivered between the Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (herein referred to as the “Trustee”, which term includes any successor trustee under the Indenture), to which Indenture reference is hereby made for a description of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Trustee, the Company and the registered Holders of the Notes and of the terms upon which the Notes are, and are to be, authenticated and delivered.

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

This Note will be redeemable at the option of the Company, in whole at any time or in part from time to time (any such date of optional redemption, an “Optional Redemption Date,” which shall be a “Redemption Date” for purposes of the Indenture) at the redemption prices set forth below. At any time prior to March 1, 2024 the optional redemption price (which shall be a “Redemption

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Price” for purposes of the Indenture) will be equal to the greater of (i) 100% of the principal amount of this Note to be redeemed and (ii) the sum of the present values of the principal amount of this Note to be redeemed and the remaining scheduled payments of interest on the principal amount of this Note to be redeemed (exclusive of interest accrued to the related Optional Redemption Date) until Stated Maturity, in each case discounted from their respective scheduled payment dates to such Optional Redemption Date on a semiannual basis (assuming a 360-day year consisting of 30-day months) at the Adjusted Treasury Rate (as defined below) plus 15 basis points, as determined by the Quotation Agent (as defined below), plus in either case, accrued interest thereon to the date of redemption. At any time on or after March 1, 2024, the optional redemption price will be equal to 100% of the principal amount of this bond to be redeemed plus accrued and unpaid interest thereon to the redemption date.

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

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

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

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

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

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

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

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at 5:00 p.m., New York City time, on the third Business Day preceding such Optional Redemption Date.

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

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

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

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

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

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

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registration of transfer or otherwise), irrespective of whether or not any notation of such consent or waiver is made upon this Note.

No reference herein to the Indenture and no provision of this Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and premium, if any, and interest on this Note at the time and place and at the rate and in the coin or currency herein prescribed.

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

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

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

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

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

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

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

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

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

DTE ENERGY COMPANY

By: _________________________________

Name: 

Title: 

Date: May __, 2014

Attest:

By: _________________________________

Name: 

Title: 

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CERTIFICATE OF AUTHENTICATION

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

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

By __________________________
Authorized Signatory

Date: May__, 2014

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

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

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

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

Dated:________________________

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

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EX-10.90

Exhibit 10-90

CHANGE-IN-CONTROL SEVERANCE AGREEMENT

This CHANGE-IN-CONTROL SEVERANCE AGREEMENT (the “Agreement”) is entered into as of __________________, 2014 (the “Effective Date”) between DTE Energy Company, a Michigan corporation (the “Company”), and ___________________ (the “Executive”).

RECITALS

A.The Executive is an executive or a key employee of the Company or one or more of its Subsidiaries and has made and is expected to continue to make major contributions to the short- and long-term profitability, growth and financial strength of the Company.

B.The Company recognizes that, as is the case for most publicly held companies, the possibility of a Change-in-Control exists and that potential employment uncertainty resulting from a Change-in-Control may distract management from conducting the Company’s business or cause management employees to leave the Company’s employ.

C.The Company wants to provide security to its senior executives and key employees to enable them to discharge their duties during the consideration and consummation of a Change-in-Control in order to preserve the value of the Company for its shareholders.

In consideration of these objectives, the Company and the Executive agree as follows:

1.Term of Agreement. The term of this Agreement (the “Term”) begins on the Effective Date and ends on the earlier of:

(a)the later of:

(1)the Agreement Expiration Date; or

(2)the last day of the Severance Period.

or

(b)the date prior to a Change-in-Control on which the Executive ceases for any reason to be an employee of the Company and any Subsidiary. For purposes of this Section 1(b), the Executive does not cease to be an employee of the Company and any Subsidiary if the Executive’s employment is transferred between the Company and any Subsidiary, or among any Subsidiaries.

2.Right to Receive Severance Benefits. The Executive will become entitled to the severance benefits provided under this Agreement if the Executive’s employment is terminated because of a Qualifying Termination.

FORM APPROVED 02.05.2014

Organization and Compensation Committee

3.Severance Benefits.

(a)The Severance Benefits payable under this Agreement are all of the following:

(1)A lump sum payment equal to the sum of:

(A)Base Pay; plus

(B)the greater of:

(i)the Annual Bonus for the year in which the Change-in-Control occurs; or

(ii)the Annual Bonus for the year in which the Termination Date occurs,

in either case based on the assumption that target performance goals for the applicable year would be met and the Executive was employed for the entire year or until any later date required to receive the payment.

(2)A lump sum payment equal to:

(A)the greater of:

(i)the Annual Bonus for the year in which the Change-in-Control occurs; or

(ii)the Annual Bonus for the year in which the Termination Date occurs,

in either case calculated based on the assumption that target performance goals for the applicable year would be met and the Executive was employed for the entire year or until any later date required to receive such payment,

(B)multiplied by the following fraction:

(i)the numerator is the number of days prior to the Executive’s Termination Date during the calendar year in which the Termination Date occurs; and

(ii)the denominator is 365,

(C)then reduced by the Annual Bonus for the year in which the Termination Date occurs that is payable to the Executive under the terms of the Annual Plan because the Executive has attained age 55 and completed 10 years of service with the Company and all Subsidiaries.

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(3)For Welfare Benefits provided to the Executive immediately prior to the Executive’s Termination Date (or, if greater, immediately prior to reduction, termination, or denial), a lump sum payment equal to the present value of the cost of coverage for the Benefit Continuation Period. The cost of coverage will be determined at rates in effect as of the Termination Date. The present value of the cost will be determined using an interest rate equal to the composite prime rate in effect as of the Termination Date in the Northeast Edition of The Wall Street Journal.

(4)Additional age, service, and compensation credit for the length of the Benefit Continuation Period for determining the Executive’s benefits under the following plans (or any successors to these plans):

(A)DTE Energy Company Supplemental Retirement Plan; and

(B)DTE Energy Company Executive Supplemental Retirement Plan (including the Management Supplemental Benefit Plan, if applicable to the Executive).

If the Executive’s Qualifying Termination was for Good Reason as described in Section 18(m)(4), the Executive’s benefits under the above plans will be the greater of the Executive benefits under the terms of the plans as of the Executive’s Termination Date or before the termination, denial, or material reduction.

(5)Outplacement services by a firm selected by the Executive, at a cost to the Company in an amount up to 15% of the Executive’s Base Pay. No payments by the Company for outplacement services will be made after December 31^st of the calendar year following the calendar year including the Termination Date.

4.Timing of Payments.

(a)Payments under the following Sections will be paid on the later of 60 days after the Executive’s Termination Date or any later date required by Code Section 409A or any other law:

(1)Section 3(a)(1);

(2)Section 3(a)(2);

(3)Section 3(a)(3); and

(4)Section 3(a)(6)

(b)Withholding of Taxes. The Company will withhold from any amounts payable under this Agreement all federal, state, city or other taxes that the Company is required to withhold under any law or government regulation or ruling.

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(c)Interest. If the Company fails to make any payment or provide any benefit required to be made or provided under this Agreement on a timely basis, the Company will pay interest on the amount or value at an annualized rate of interest equal to the composite prime rate as quoted from time to time during the relevant period in the Northeast Edition of The Wall Street Journal. The interest is payable as it accrues on demand, but the Company is not required to pay interest more frequently than monthly. Any change in the prime rate will be effective on and as of the date of the change.

5.Non-Duplication of Severance Benefits.

(a)Qualifying Termination During Concurrent Severance Periods. If the Executive experiences a Qualifying Termination when two or more Severance Periods are running concurrently (because two or more Changes-in-Control have occurred), the Executive will have a Qualifying Termination with respect to each Severance Period. A determination of the payments and benefits to be provided under the Agreement will be made for each Qualifying Termination. However, the Executive will receive only:

(1)the greatest lump sum payment under Section 3(a)(1) payable for any Qualifying Termination;

(2)the greatest lump sum payment under Section 3(a)(2) for any Qualifying Termination;

(3)the greatest lump sum payment under Section 3(a)(3) for any Qualifying Termination; and

(4)the greatest benefits under Section 3(a)(4) for any Qualifying Termination.

(b)Effect on Other Employee Benefits. The Executive’s Qualifying Termination will not affect any rights the Executive may have under any agreement, policy, plan, program or arrangement of the Company or Subsidiary providing Employee Benefits (other than Severance Pay), which rights are governed by the terms of the agreement, policy, plan, program or arrangement. The benefits received by an Executive under this Agreement because of a Qualifying Termination supersede and are in lieu of any other Severance Pay to which the Executive may be entitled.

6.Mitigation. The Company acknowledges that it will be difficult and may be impossible for the Executive to find reasonably comparable employment following the Termination Date. Accordingly, the Company acknowledges that payment of the severance compensation by the Company to the Executive under this Agreement is reasonable. The Executive is not required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise. No profits, income, earnings or other benefits from any source will create any mitigation, offset, reduction or other obligation on the part of the Executive, except as may have been otherwise paid to the Executive by the Company or a Subsidiary in connection with or in consideration of Executive’s release and settlement of any claims arising out of the Executive’s employment or the termination of the Executive’s employment.

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7.Arbitration; Legal Fees and Expenses.

(a)Except for legal proceedings brought by the Executive or the Company for injunctive relief, any dispute or claim involving this Agreement will be submitted to final and binding arbitration. The arbitration will take place in Oakland County, Michigan before a single neutral arbitrator under the then-current National Rules for the Resolution of Employment Disputes of the American Arbitration Association. The arbitrator will issue a written opinion and will not have authority to render an award beyond the scope and specific terms of this Agreement. Judgment upon the arbitrator’s award may be entered in any court of competent jurisdiction. Any demand for arbitration must be made within 30 days of when the party knew or should have known of the alleged dispute or claim. Failure to timely demand arbitration makes the dispute or claim non-arbitrable. The Executive and the Company expressly waive their rights to institute or prosecute any lawsuits or other court proceedings and waive their right to a jury trial, except for the legal proceedings excluded above.

(b)It is the intent of the Company that the Executive not be required to incur legal fees and the related expenses associated with the interpretation, enforcement or defense of Executive’s rights under this Agreement because the legal fees and related expenses would substantially detract from the benefits intended to be extended to the Executive under this Agreement.

(c)If it appears to the Executive that the Company has failed to comply with any of its obligations under this Agreement or if the Company or any other person takes or threatens to take any action to declare this Agreement void or unenforceable, or institutes any action or proceeding designed to deny, or to recover from, the Executive the benefits provided or intended to be provided to the Executive under this Agreement, the Company irrevocably authorizes the Executive to retain counsel of Executive’s choice, at the expense of the Company as provided in this Section 7, to advise and represent the Executive in connection with any interpretation, enforcement or defense of the Executive’s rights under this Agreement.

(d)The Executive may pursue any legal defense of the Executive’s rights under this Agreement whether by or against the Company or any Director, officer, stockholder or other person affiliated with the Company, in any jurisdiction.

(e)Whether or not the Executive prevails in connection with any defense of the Executive’s rights under this Agreement, the Company will pay and be solely financially responsible for reasonable hourly attorneys’ fees and related fees and expenses incurred by the Executive under this Section 7, but only if the arbitrator determines the Executive’s claim was brought in good faith and was not frivolous. If the Executive’s request for injunctive relief is denied and the Executive does not timely demand arbitration for the dispute or claim underlying the Executive’s request for injunctive relief, the Executive’s request for injunctive relief is deemed to be frivolous and not brought in good faith for purposes of this Section 7(e).

(f)The Company’s payment of the Executive’s legal fees and expenses under this Section 7 following termination of the Executive’s employment (whether or not in a

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Qualifying Termination) will be made during the first calendar year beginning after the date the Executive’s employment terminated.

8.Survival of Rights and Obligations. The rights and obligations of the Executive and the Company under the following Sections will survive the termination or expiration of this Agreement and the termination of the Executive’s employment after a Change-in-Control for any reason:

(a)Section 3 (Severance Benefits);

(b)Section 4 (Timing of Payments);

(c)Section 5 (Non-Duplication of Severance Benefits);

(d)Section 6 (Mitigation); and

(e)Section 7 (Legal Fees).

9.Confidential Information; Non-Disparagement; Non-Solicitation; Competitive Activity.

(a)Confidential Information. At all times following the Termination Date, the Executive will not, without the prior written consent of the Company, either directly or indirectly use, appropriate, or disseminate, disclose, or communicate to any person or entity any confidential information of the Company or any Subsidiary that is now known or later becomes known to the Executive because of the Executive’s employment with the Company or any Subsidiary, unless the disclosure is required by a valid subpoena or order issued by a court or governmental body.

(1)For purposes of this Section 9(a), “confidential information” is any confidential, proprietary, or trade secret information, including concepts, ideas, information, and materials related to the Company or any Subsidiary, customer records, customer lists, economic and financial analyses, financial data, customer contracts, marketing plans, notes, memoranda, lists, books, correspondence, manuals, reports or research, whether developed by the Company or a Subsidiary or developed by the Executive while employed by the Company or a Subsidiary.

(2)This Section 9(a) does not apply to any confidential information that becomes publicly disseminated by means other than a breach of this provision.

(b)Non-Disparagement. The Executive will not make any verbal or written comments to any third party that are defamatory, disparaging, or critical of the Company or any Subsidiary or its products, management, employees, officers or operations or that would otherwise adversely affect the finances or business reputation of the Company or any Subsidiary.

(c)Non-Solicitation.

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(1)For a period of two years after the Termination Date, the Executive will not solicit, divert, take away, or attempt to take away any customer of the Company or any Subsidiary or the business of any customer of the Company or any Subsidiary.

(A)A “customer” of the Company or any Subsidiary is any person or other entity to which the Company or any Subsidiary has sold services or products during the 24-month period immediately preceding the Termination Date, any person or other entity that the Company or any Subsidiary is in the process of selling services or products, or any person or other entity to which the Company or any Subsidiary has submitted or is in the process of submitting a bid to sell services or products.

(2)For a period of two years after the Termination Date, the Executive will not solicit, attempt to employ, or employ any individual who is an employee, consultant, or agent of the Company or any Subsidiary.

(d)Competitive Activity. For a period of one year following the Termination Date, the Executive will not engage in any Competitive Activity.

10.Employment Rights. Nothing in this Agreement creates any right or duty on the part of the Company or the Executive to have the Executive remain in the employment of the Company or any Subsidiary prior to or following any Change-in-Control.

11.Successors and Binding Agreement.

(a)The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization or otherwise) to all or substantially all of the business or assets of the Company, by agreement in form and substance satisfactory to the Executive, to expressly assume and agree to perform this Agreement in the same manner and to the same extent the Company would be required to perform it if the succession had not taken place. This Agreement will be binding upon and inure to the benefit of the Company and any successor to the Company, including without limitation any person acquiring directly or indirectly all or substantially all of the business or assets of the Company by purchase, merger, consolidation, reorganization or otherwise, with the successor thereafter deemed to be the “Company” for the purposes of this Agreement. Other than as permitted under this Section 11(a), this Agreement is not assignable, transferable or delegable by the Company.

(b)This Agreement will inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees and legatees.

(c)This Agreement is personal in nature and neither of the parties may, without the consent of the other, assign, transfer or delegate this Agreement or any rights or obligations hereunder except as expressly provided in Sections 11(a) and 11(b). The Executive’s right to receive payments under the Agreement is not assignable, transferable or delegable, including by pledge, creation of a security interest, or otherwise, other than by a transfer by Executive’s will or by the laws of descent and distribution. If any assignment or transfer

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not permitted by this Section 11(c) is attempted, the Company will have no liability to pay any amount attempted to be assigned, transferred or delegated.

12.Notices.

(a)All communications, including notices, consents, requests or approvals, required or permitted to be given under this Agreement must be in writing.

(b)All notices must be provided by:

(1)hand delivery (deemed provided when delivered);

(2)electronic facsimile transmission, with verbal confirmation of receipt (deemed provided when transmitted);

(3)United States registered or certified mail, return receipt requested, postage prepaid (deemed provided five business days after mailing); or

(4)a nationally recognized overnight courier service such as Federal Express or UPS (deemed provided three business days after deposit with courier service).

(c)Notices to the Company must be addressed to the attention of the Vice President - Human Resources of the Company at the Company’s principal executive office.

(d)Notices to the Executive must be addressed to the Executive at the Executive’s principal residence.

(e)The Company or the Executive can change the address to which notices to that party are to be addressed by providing notice to the other party as required under this Section 12, except that notices of changes of address are effective only upon actual receipt.

13.Governing Law. The validity, interpretation, construction and performance of this Agreement will be governed by and construed in accordance with the substantive laws of the State of Michigan, without giving effect to its principles of conflict of laws.

14.Validity. If any provision of this Agreement or the application of any provision to any person or circumstances is held invalid, unenforceable or otherwise illegal by a court of competent jurisdiction, the remainder of this Agreement and the application of the provision to any other person or circumstances will not be affected. The provision held to be invalid, unenforceable or otherwise illegal will be amended to the minimum extent necessary to make it enforceable, valid or legal.

15.Miscellaneous.

(a)No provision of this Agreement may be modified, waived or discharged unless the waiver, modification or discharge is agreed to in writing signed by the Executive and the Company.

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(b)No waiver by either party at the time of any breach by the other party or compliance with any condition or provision of this Agreement to be performed by the other party will be a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

(c)No agreements or representations, oral or otherwise, expressed or implied, with respect to the subject matter of this Agreement have been made by either party which are not set forth expressly in this Agreement.

(d)References to Sections are to references to Sections of this Agreement.

16.Prior Agreements. As of the Effective Date, this Agreement supersedes and replaces all prior change-in-control severance agreements and similar agreements between the Executive and the Company or any of its Subsidiaries (“Prior Agreements”). All Prior Agreements cease to be of force and effect as of the Effective Date.

17.Counterparts. This Agreement may be executed in one or more counterparts, each of which is deemed an original but all of which together will constitute one agreement.

18.Definitions. For purposes of this Agreement, the following definitions apply:

(a)Agreement Expiration Date is the later of:

(1)the day before the third anniversary of the Effective Date; or

(2)the last day of any extension of the Agreement under this Section 18(a).

Beginning onthe first anniversary of the Effective Date and on each subsequent anniversary of the Effective Date, this Agreement will automatically be extended for an additional year unless, not later than 90 days preceding any anniversary of the Effective Date:

(3)the Company gives notice that it does not wish to have the Term extended; or

(4)the Com-pany gives notice that it wishes the Term to be extended for a period of less than one year, in which case the term of the Agreement will automatically be extended for the shorter period and will then terminate if not further extended by written agreement between the Company and the Executive.

(b)Annual Bonus is the aggregate annual bonus to which the Executive would have been entitled under the DTE Energy Company Annual Incentive Plan, a Subsidiary’s annual incentive plan, or any successor annual incentive plan (an “Annual Plan”) in the applicable year, presuming that the Executive’s individual performance multiplier is 100%. If the Executive participates in an Annual Plan without a specified target, the Executive’s Annual Bonus is 1/3 of the sum of the Executive’s payments under the Annual Plan for the three years preceding the applicable year (even if the Executive has not participated in the plan for three years).

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(c)Base Pay is the Executive’s annual base salary (prior to any pre-tax deferrals made under any employee benefit plans of the Company) in effect immediately prior to the Change-in-Control or immediately prior to the Executive’s Termination Date, if higher.

(d)Benefit Continuation Period is the two-year period beginning on the Executive’s Termination Date.

(e)Board is the Board of Directors of the Company.

(f)Cause. The Executive’s employment will be considered terminated for Cause if prior to termination of the Executive’s employment, the Board reasonably determines, based on a preponderance of the evidence reasonably available to the Board as of the date the Board adopts the resolution described below, that the Executive committed or engaged in:

(1)an intentional act of fraud, embezzlement or theft at a level that constitutes a felony in connection with the Executive’s duties or in the course of the Executive’s employment with the Company or a Subsidiary, whether or not the Executive is convicted or pleads guilty or nolo contender (no contest) to any related criminal charges;

(2)intentional wrongful damage to property of the Company or a Subsidiary;

(3)intentional wrongful disclosure of secret processes or confidential information of the Company or a Subsidiary;

(4)intentional wrongful engagement in any Competitive Activity;

(5)willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company that is not cured within 30 days after the Board delivers to the Executive a written demand for substantial performance specifically identifying the Executive’s failure to perform; or

(6)other intentional activity, including but not limited to a breach of the Executive’s fiduciary duties with respect to the Company, a Subsidiary, or any welfare plan or pension plan sponsored by the Company or a Subsidiary;

which, in the reasonable judgment of the Board and based on a preponderance of the evidence available to the Board is significantly detrimental to the reputa-tion, goodwill or business of the Company or significantly disrupts the workplace environment or operation of the Company’s business or administrative activities.

For pur-poses of this Agreement, no act or failure to act on the part of the Executive will be deemed “intentional” if it was due primarily to an error in the Executive’s judgment or the Executive’s negligence. An act will be deemed “intentional” only if done or omitted to be done by the Executive not in good faith and without reasonable belief that the Executive’s action or omission was in the best interest of the Company.

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For purposes of this Agreement, the Executive has not been terminated for Cause unless and until:

(7)a meeting of the Board is called and held for the purpose of determining if the Executive is to be terminated for Cause; and

(8)the Executive is given reasonable notice of the meeting and an opportunity to be heard before the Board, with Executive’s counsel if Executive so chooses; and

(9)at that meeting the Board finds, in the good faith opinion of the Board, that the Executive has committed an act entitling the Board to terminate the Executive’s employment for Cause; and

(10)the Executive has been provided a copy of the resolution duly adopted at that meeting by the affirmative vote of not less than three-quarters of the Board then in office and specifying in detail the particulars of the Board’s finding.

The Executive and the Executive’s beneficiaries retain the right to contest the validity or propriety of the Board’s determination that the Executive’s employment has been terminated for Cause.

(g)Change-in-Control occurs if any of the following events occurs during the Term of this Agreement:

(1)The Company is merged, consolidated or reorganized into or with another corporation or other legal person, and as a result of the merger, consolidation or reorganization less than 55% of the combined voting power of the then-outstanding Voting Stock of the other corporation or person immediately after the transaction is held in the aggregate by the holders of Voting Stock of the Company immediately prior to the transaction;

(2)The Company sells or otherwise transfers all or substantially all of its assets to another corporation or other legal person, and as a result of the sale or transfer less than 55% of the combined voting power of the then-outstanding Voting Stock of the acquiring corporation or person immediately after the sale or transfer is held in the aggregate (directly or through ownership of Voting Stock of the Company or a Subsidiary) by the holders of Voting Stock of the Company immediately prior to the sale or transfer;

(3)A report is filed on Schedule 13D or Schedule 14D-1 (or any successor schedule, form or report) under the Exchange Act disclosing that any person (as the term “person” is used in Section 13(d)(3) or Section 14(d)(2) of the Exchange Act) has become the beneficial owner (as the term “beneficial owner” is defined under Rule 13d-3 or any successor rule or regulation promulgated under the Exchange Act) of securities representing 20% or more of the combined voting power of the then-outstanding Voting Stock of the Company. However, unless other-wise determined by majority vote of the Board, a Change-in-Control does not occur solely because

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(A) the Company, (B) a Subsidiary, or (C) any Company-sponsored employee stock ownership plan or any other employee benefit plan of the Company or a Subsidiary either files or becomes obligated to file a report or a proxy statement under or in response to Schedule 13D or Schedule 14D-l disclosing beneficial ownership by it of shares of Voting Stock, whether in excess of 20% or otherwise;

(4)During a period of two consecutive years, individuals who at the beginning of the period constitute the Directors of the Company cease for any reason to constitute at least a majority of the Directors of the Company. However, for purposes of this clause, each Director who is first elected, or first nominated for election by the Company’s stockholders, by a vote of at least two-thirds of the Directors of the Company (or of a committee of the Board) then still in office who were Directors of the Company at the beginning of the period will be deemed to have been a Director of the Company at the beginning of the period;

(5)Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company; or

(6)Execution by the Company, at the direction of the Board, of one or more definitive agreements with another corporation or other legal person to engage in a transaction that will result in a Change-in-Control described in paragraphs (1) through (5) of this Section 18(g).

(h)Code is the Internal Revenue Code of 1986, as amended.

(i)Competitive Activity is the Executive’s direct employment, without the written consent of the Board (or any Committee of the Board to which the Board delegates its authority under this Section 18(i) in writing), in any business or enterprise (including the Executive’s own business or enterprise) if:

(1)the business or enterprise engages in substantial and direct competition with the Company or any of its Subsidiaries in any state in which the Company or Subsidiary was engaged in business or actively negotiating to enter business on the Termination Date; and

(2)the business’s or enterprise’s sales of any product or service competitive with any product or service of the Company or any of its Subsidiaries amounted to 10% of the business’s or enterprise’s net sales for its most recently completed fiscal year; and

(3)the Company’s or Subsidiary’s net sales of the competitive product or service amounted to 10% of the Company’s or Subsidiary’s net sales for its most recently completed fiscal year; and

(4)the Board determines the Executive’s employment in the business or enterprise is detrimental to the Company or any of its Subsidiaries.

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“Competitive Activity” does not include the mere ownership of not more than 10% of the total combined voting power or aggregate value of all classes of stock or other securities in the enterprise and the Executive’s exercise of rights resulting from ownership of the stock.

The Board (or its delegate) has sole discretion and authority to determine if the Executive is engaging in Competitive Activity for purposes of this Agreement.

It is the Executive’s responsibility to provide information sufficient for the Board (or its delegate) to make these determinations.

(j)Employee Benefits are the perquisites, benefits and service credit for benefits provided under all employee retirement income and welfare benefit policies, plans, programs or arrangements in which Executive is entitled to participate, including without limitation any stock option, stock purchase, stock appreciation, savings, pension, supplemental executive retirement, or other retirement income or welfare benefit, deferred compensation, incentive compensation, group or other life, health, medical/hospital or other insurance (whether funded by actual insurance or self-insured by the Company or a Subsidiary), disability, salary continuation, expense reimbursement and other employee benefit policies, plans, programs or arrangements that may now exist or any equivalent successor policies, plans, programs or arrangements that may be adopted hereafter by the Company or a Subsidiary, providing perquisites, benefits and service credit for benefits at least as great in the aggregate as are payable prior to a Change-in-Control.

(k)ERISA is the Employee Retirement Income Security Act of 1974, as amended.

(l)Exchange Act is the Securities Exchange Act of 1934, as amended.

(m)Good Reason. An Executive terminates employment for Good Reason if the Executive terminates his or her employment during the Severance Period following the occurrence of any of the following events during the Severance Period:

(1)failure to elect or reelect to the office, or otherwise maintain the Executive in a position within the same or higher Executive Grouping Level (as in existence prior to the Change-in-Control) with the Company and/or a Subsidiary, as applicable, which the Executive held immediately prior to the Change-in-Control, or the removal of the Executive as Chairman of the Company (or any successor to the Company) if the Executive was Chairman of the Company immediately prior to the Change-in-Control;

(2)a significant adverse change in the nature or scope of the authorities, powers, functions, responsibilities or duties attached to the position with the Company and its Subsidiaries as compared to other executives in the same Executive Grouping Level within the Company or the Subsidiary which the Executive held immediately prior to the Change-in-Control;

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(3)a reduction in the Executive’s Base Pay or the opportunity to earn Incentive Pay from the Company, its Subsidiaries or the failure to pay the Executive Base Pay or Incentive Pay earned when due;

(4)the termination or denial of the Executive’s rights to Employee Benefits or a material reduction in the aggregate scope or value of Employee Benefits (unless, in the case of Welfare Benefits or Pension Benefits the termination, denial or reduction applies to all similarly situated employees of the Company and its Subsidiaries), any of which is not remedied by the Company within 10 calendar days after the Company receives written notice from the Executive of the change, reduction or termination;

(5)the liquidation, dissolution, merger, consolidation or legal reorganization of the Company or transfer of all or substantially all of its business or assets, or both, unless the successor or successors (by liquidation, merger, consolidation, reorganization, transfer or otherwise) to which all or substantially all of its business or assets, or both, have been transferred (directly or by operation of law) assumes all duties and obligations of the Company under this Agreement under Section 1l(a);

(6)without the Executive’s prior written consent, the Company:

(A)requires the Executive to change the Executive’s principal location of work to any location that is in excess of 300 miles from the location immediately prior to the Change-in-Control;

or

(B)requires the Executive to travel away from the Executive’s office in the course of discharging the Executive’s responsibilities or duties at least 40% more (in terms of aggregate days in any calendar year or in any calendar quarter when annualized for purposes of comparison to any prior year) than the average number of travel days per calendar year that was required of Executive in the three full calendar years immediately prior to the Change-in-Control; or

(7)any material breach of this Agreement by the Company or its successor.

(n)Incentive Pay is the aggregate annual payments of cash or equity compensation (determined without regard to any deferral election) and annual vesting of equity compensation, in addition to Base Pay, under any bonus, incentive, profit-sharing, performance, discretionary pay or similar agreement, policy, plan, program or arrangement (whether or not funded) of the Company or a Subsidiary, or any successor, providing economic value on an aggregate basis at least as favorable to the Executive, in terms of the amount of benefits, levels of coverage and performance measures and levels of required performance, as the benefits payable prior to the Change-in-Control.

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(o)Qualifying Termination means:

(1)Termination of the Executive’s employment by the Company or a Subsidiary during the Severance Period other than a termination:

(A)because of the Executive’s death;

(B)because the Executive became permanently disabled within the meaning of, and began receiving disability benefits under, the Company or Subsidiary sponsored long-term disability plan in effect for, or applicable to, the Executive immediately prior to the Change-in-Control; or

(C)for Cause;

or

(2)Termination of the Executive’s employment by the Executive during the Severance Period for Good Reason, regardless of whether any other reason, other than Cause, for the Executive’s termination exists or has occurred, including other employment.

(p)Pension Benefits are benefits provided under employee pension benefit plans as defined in Section 3(2)(A) of ERISA, but excluding employee pension benefit plans described in Section 201(2) of ERISA.

(q)Severance Pay is the collective benefits provided under any agreement, policy, plan, program, or arrangement of the Company or a Subsidiary or any provision of any individual severance, employment, or other agreement between the Executive and the Company or a Subsidiary that are paid to the Executive solely because of the termination of the Executive’s employment.

(r)Severance Period resulting from a Change-in-Control described in Sections 18(g)(1) through (5) is the period beginning on the date a Change-in-Control occurs and ending on the earlier of:

(1)the second anniversary of the Change-in-Control; or

(2)the Executive’s death.

The Severance Period resulting from a Change-in-Control described in Section 18(g)(6) is the period beginning on the date the Change-in-Control occurs and ending on the earliest of:

(3)the second anniversary of the Change-in-Control;

(4)the Executive’s death; or

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(5)the date the transaction is abandoned, as determined by the Board in a resolution adopted in good faith.

(s)Subsidiary is an entity in which the Company directly or indirectly beneficially owns 50% or more of the outstanding Voting Stock.

(t)Termination Date is the date on which the Executive’s employment is terminated by a Qualifying Termination.

(u)Welfare Benefits are benefits provided under employee welfare benefit plans, as defined in Section 3(1) of the Employee Retirement Income Security Act of 1974, as amended.

(v)Voting Stock is securities entitled to vote generally in the election of Directors.

In witness whereof, this Agreement has been entered into by the Company and the Executive as of the Effective Date.

____________________________________    

[Executive’s Name]

DTE ENERGY COMPANY

_____________________________________    

Gerard M. Anderson

Chairman & Chief Executive Officer

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EX-10.91

Exhibit 10-91

CHANGE-IN-CONTROL SEVERANCE AGREEMENT

This CHANGE-IN-CONTROL SEVERANCE AGREEMENT (the “Agreement”) is entered into as of __________________, 2014 (the “Effective Date”) between DTE Energy Company, a Michigan corporation (the “Company”), and ___________________ (the “Executive”).

RECITALS

A.The Executive is an executive or a key employee of the Company or one or more of its Subsidiaries and has made and is expected to continue to make major contributions to the short- and long-term profitability, growth and financial strength of the Company.

B.The Company recognizes that, as is the case for most publicly held companies, the possibility of a Change-in-Control exists and that potential employment uncertainty resulting from a Change-in-Control may distract management from conducting the Company’s business or cause management employees to leave the Company’s employ.

C.The Company wants to provide security to its senior executives and key employees to enable them to discharge their duties during the consideration and consummation of a Change-in-Control in order to preserve the value of the Company for its shareholders.

In consideration of these objectives, the Company and the Executive agree as follows:

1.Term of Agreement. The term of this Agreement (the “Term”) begins on the Effective Date and ends on the earlier of:

(a)the later of:

(1)the Agreement Expiration Date; or

(2)the last day of the Severance Period.

or

(b)the date prior to a Change-in-Control on which the Executive ceases for any reason to be an employee of the Company and any Subsidiary. For purposes of this Section 1(b), the Executive does not cease to be an employee of the Company and any Subsidiary if the Executive’s employment is transferred between the Company and any Subsidiary, or among any Subsidiaries.

2.Right to Receive Severance Benefits and Other Consideration. The Executive will become entitled to the severance benefits and other consideration provided under this Agreement if the Executive’s employment is terminated because of a Qualifying Termination.

FORM APPROVED 02.05.2014

Organization and Compensation Committee

3.Severance Benefits and Other Consideration.

(a)Severance Benefits. The Severance Benefits payable under this Agreement are all of the following:

(1)A lump sum payment equal to the sum of:

(A)Base Pay; plus

(B)the greater of:

(i)the Annual Bonus for the year in which the Change-in-Control occurs; or

(ii)the Annual Bonus for the year in which the Termination Date occurs,

in either case based on the assumption that target performance goals for the applicable year would be met and the Executive was employed for the entire year or until any later date required to receive the payment;

multiplied by:

(C)the lesser of:

(i)150%; or

(ii)150% multiplied by a fraction, the numerator of which is the number of full calendar months from the Executive’s Termination Date to the Executive’s 65^th birthday, and the denominator of which is 24.

(2)A lump sum payment equal to:

(A)the greater of:

(i)the Annual Bonus for the year in which the Change-in-Control occurs; or

(ii)the Annual Bonus for the year in which the Termination Date occurs,

in either case calculated based on the assumption that target performance goals for the applicable year would be met and the Executive was employed for the entire year or until any later date required to receive such payment,

(B)multiplied by the following fraction:

2

(i)the numerator is the number of days prior to the Executive’s Termination Date during the calendar year in which the Termination Date occurs; and

(ii)the denominator is 365,

(C)then reduced by the Annual Bonus for the year in which the Termination Date occurs that is payable to the Executive under the terms of the Annual Plan because the Executive has attained age 55 and completed 10 years of service with the Company and all Subsidiaries.

(3)For Welfare Benefits provided to the Executive immediately prior to the Executive’s Termination Date (or, if greater, immediately prior to reduction, termination, or denial), a lump sum payment equal to the present value of the cost of coverage for the Benefit Continuation Period. The cost of coverage will be determined at rates in effect as of the Termination Date. The present value of the cost will be determined using an interest rate equal to the composite prime rate in effect as of the Termination Date in the Northeast Edition of The Wall Street Journal.

(4)Additional age, service, and compensation credit for the length of the Benefit Continuation Period for determining the Executive’s benefits under the following plans (or any successors to these plans):

(A)DTE Energy Company Supplemental Retirement Plan; and

(B)DTE Energy Company Executive Supplemental Retirement Plan (including the Management Supplemental Benefit Plan, if applicable to the Executive).

If the Executive’s Qualifying Termination was for Good Reason as described in Section 18(m)(4), the Executive’s benefits under the above plans will be the greater of the Executive benefits under the terms of the plans as of the Executive’s Termination Date or before the termination, denial, or material reduction.

(5)Outplacement services by a firm selected by the Executive, at a cost to the Company in an amount up to 15% of the Executive’s Base Pay. No payments by the Company for outplacement services will be made after December 31^st of the calendar year following the calendar year including the Termination Date.

(b)Other Consideration. The consideration for the restrictive covenant in Section 9(d) (Competitive Activity) is a lump sum payment equal to:

(1)the sum of:

(A)Base Pay; plus

(B)the greater of:

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(i)the Annual Bonus for the year in which the Change-in-Control occurs; or

(ii)the Annual Bonus for the year in which the Termination Date occurs,

in either case based on the assumption that target performance goals for the applicable year would be met and the Executive was employed for the entire year or until any later date required to receive the payment;

multiplied by

(C)the lesser of:

(i)50%; or

(ii)50% multiplied by a fraction, the numerator of which is the number of full calendar months from the Executive’s Termination Date to the Executive’s 65^th birthday, and the denominator of which is 24.

4.Timing of Payments.

(a)Payments under the following Sections will be paid on the later of 60 days after the Executive’s Termination Date or any later date required by Code Section 409A or any other law:

(1)Section 3(a)(1);

(2)Section 3(a)(2);

(3)Section 3(a)(3);

(4)Section 3(a)(6); and

(5)Section 3(b).

(b)Withholding of Taxes. The Company will withhold from any amounts payable under this Agreement all federal, state, city or other taxes that the Company is required to withhold under any law or government regulation or ruling.

(c)Interest. If the Company fails to make any payment or provide any benefit required to be made or provided under this Agreement on a timely basis, the Company will pay interest on the amount or value at an annualized rate of interest equal to the composite prime rate as quoted from time to time during the relevant period in the Northeast Edition of The Wall Street Journal. The interest is payable as it accrues on demand, but the Company is

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not required to pay interest more frequently than monthly. Any change in the prime rate will be effective on and as of the date of the change.

5.Non-Duplication of Severance Benefits and Other Consideration.

(a)Qualifying Termination During Concurrent Severance Periods. If the Executive experiences a Qualifying Termination when two or more Severance Periods are running concurrently (because two or more Changes-in-Control have occurred), the Executive will have a Qualifying Termination with respect to each Severance Period. A determination of the payments and benefits to be provided under the Agreement will be made for each Qualifying Termination. However, the Executive will receive only:

(1)the greatest lump sum payment under Section 3(a)(1) payable for any Qualifying Termination;

(2)the greatest lump sum payment under Section 3(a)(2) for any Qualifying Termination;

(3)the greatest lump sum payment under Section 3(a)(3) for any Qualifying Termination;

(4)the greatest benefits under Section 3(a)(4) for any Qualifying Termination; and

(5)the greatest lump sum payment under Section 3(b) for any Qualifying Termination.

(b)Effect on Other Employee Benefits. The Executive’s Qualifying Termination will not affect any rights the Executive may have under any agreement, policy, plan, program or arrangement of the Company or Subsidiary providing Employee Benefits (other than Severance Pay), which rights are governed by the terms of the agreement, policy, plan, program or arrangement. The benefits received by an Executive under this Agreement because of a Qualifying Termination supersede and are in lieu of any other Severance Pay to which the Executive may be entitled.

6.Mitigation. The Company acknowledges that it will be difficult and may be impossible for the Executive to find reasonably comparable employment following the Termination Date. Accordingly, the Company acknowledges that payment of the severance compensation by the Company to the Executive under this Agreement is reasonable. The Executive is not required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise. No profits, income, earnings or other benefits from any source will create any mitigation, offset, reduction or other obligation on the part of the Executive, except as may have been otherwise paid to the Executive by the Company or a Subsidiary in connection with or in consideration of Executive’s release and settlement of any claims arising out of the Executive’s employment or the termination of the Executive’s employment.

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7.Arbitration; Legal Fees and Expenses.

(a)Except for legal proceedings brought by the Executive or the Company for injunctive relief, any dispute or claim involving this Agreement will be submitted to final and binding arbitration. The arbitration will take place in Oakland County, Michigan before a single neutral arbitrator under the then-current National Rules for the Resolution of Employment Disputes of the American Arbitration Association. The arbitrator will issue a written opinion and will not have authority to render an award beyond the scope and specific terms of this Agreement. Judgment upon the arbitrator’s award may be entered in any court of competent jurisdiction. Any demand for arbitration must be made within 30 days of when the party knew or should have known of the alleged dispute or claim. Failure to timely demand arbitration makes the dispute or claim non-arbitrable. The Executive and the Company expressly waive their rights to institute or prosecute any lawsuits or other court proceedings and waive their right to a jury trial, except for the legal proceedings excluded above.

(b)It is the intent of the Company that the Executive not be required to incur legal fees and the related expenses associated with the interpretation, enforcement or defense of Executive’s rights under this Agreement because the legal fees and related expenses would substantially detract from the benefits intended to be extended to the Executive under this Agreement.

(c)If it appears to the Executive that the Company has failed to comply with any of its obligations under this Agreement or if the Company or any other person takes or threatens to take any action to declare this Agreement void or unenforceable, or institutes any action or proceeding designed to deny, or to recover from, the Executive the benefits provided or intended to be provided to the Executive under this Agreement, the Company irrevocably authorizes the Executive to retain counsel of Executive’s choice, at the expense of the Company as provided in this Section 7, to advise and represent the Executive in connection with any interpretation, enforcement or defense of the Executive’s rights under this Agreement.

(d)The Executive may pursue any legal defense of the Executive’s rights under this Agreement whether by or against the Company or any Director, officer, stockholder or other person affiliated with the Company, in any jurisdiction.

(e)Whether or not the Executive prevails in connection with any defense of the Executive’s rights under this Agreement, the Company will pay and be solely financially responsible for reasonable hourly attorneys’ fees and related fees and expenses incurred by the Executive under this Section 7, but only if the arbitrator determines the Executive’s claim was brought in good faith and was not frivolous. If the Executive’s request for injunctive relief is denied and the Executive does not timely demand arbitration for the dispute or claim underlying the Executive’s request for injunctive relief, the Executive’s request for injunctive relief is deemed to be frivolous and not brought in good faith for purposes of this Section 7(e).

(f)The Company’s payment of the Executive’s legal fees and expenses under this Section 7 following termination of the Executive’s employment (whether or not in a

6

Qualifying Termination) will be made during the first calendar year beginning after the date the Executive’s employment terminated.

8.Survival of Rights and Obligations. The rights and obligations of the Executive and the Company under the following Sections will survive the termination or expiration of this Agreement and the termination of the Executive’s employment after a Change-in-Control for any reason:

(a)Section 3 (Severance Benefits and Other Consideration);

(b)Section 4 (Timing of Payments);

(c)Section 5 (Non-Duplication of Severance Benefits and Other Consideration);

(d)Section 6 (Mitigation); and

(e)Section 7 (Legal Fees).

9.Confidential Information; Non-Disparagement; Non-Solicitation; Competitive Activity.

(a)Confidential Information. At all times following the Termination Date, the Executive will not, without the prior written consent of the Company, either directly or indirectly use, appropriate, or disseminate, disclose, or communicate to any person or entity any confidential information of the Company or any Subsidiary that is now known or later becomes known to the Executive because of the Executive’s employment with the Company or any Subsidiary, unless the disclosure is required by a valid subpoena or order issued by a court or governmental body.

(1)For purposes of this Section 9(a), “confidential information” is any confidential, proprietary, or trade secret information, including concepts, ideas, information, and materials related to the Company or any Subsidiary, customer records, customer lists, economic and financial analyses, financial data, customer contracts, marketing plans, notes, memoranda, lists, books, correspondence, manuals, reports or research, whether developed by the Company or a Subsidiary or developed by the Executive while employed by the Company or a Subsidiary.

(2)This Section 9(a) does not apply to any confidential information that becomes publicly disseminated by means other than a breach of this provision.

(b)Non-Disparagement. The Executive will not make any verbal or written comments to any third party that are defamatory, disparaging, or critical of the Company or any Subsidiary or its products, management, employees, officers or operations or that would otherwise adversely affect the finances or business reputation of the Company or any Subsidiary.

(c)Non-Solicitation.

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(1)For a period of two years after the Termination Date, the Executive will not solicit, divert, take away, or attempt to take away any customer of the Company or any Subsidiary or the business of any customer of the Company or any Subsidiary.

(A)A “customer” of the Company or any Subsidiary is any person or other entity to which the Company or any Subsidiary has sold services or products during the 24-month period immediately preceding the Termination Date, any person or other entity that the Company or any Subsidiary is in the process of selling services or products, or any person or other entity to which the Company or any Subsidiary has submitted or is in the process of submitting a bid to sell services or products.

(2)For a period of two years after the Termination Date, the Executive will not solicit, attempt to employ, or employ any individual who is an employee, consultant, or agent of the Company or any Subsidiary.

(d)Competitive Activity. For a period of one year following the Termination Date, the Executive will not engage in any Competitive Activity. If the Executive engages in any Competitive Activity earlier than one year following the Termination Date, the Executive must repay to the Company the consideration paid to the Executive under Section 3(b).

10.Employment Rights. Nothing in this Agreement creates any right or duty on the part of the Company or the Executive to have the Executive remain in the employment of the Company or any Subsidiary prior to or following any Change-in-Control.

11.Successors and Binding Agreement.

(a)The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization or otherwise) to all or substantially all of the business or assets of the Company, by agreement in form and substance satisfactory to the Executive, to expressly assume and agree to perform this Agreement in the same manner and to the same extent the Company would be required to perform it if the succession had not taken place. This Agreement will be binding upon and inure to the benefit of the Company and any successor to the Company, including without limitation any person acquiring directly or indirectly all or substantially all of the business or assets of the Company by purchase, merger, consolidation, reorganization or otherwise, with the successor thereafter deemed to be the “Company” for the purposes of this Agreement. Other than as permitted under this Section 11(a), this Agreement is not assignable, transferable or delegable by the Company.

(b)This Agreement will inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees and legatees.

(c)This Agreement is personal in nature and neither of the parties may, without the consent of the other, assign, transfer or delegate this Agreement or any rights or obligations hereunder except as expressly provided in Sections 11(a) and 11(b). The Executive’s right to receive payments under the Agreement is not assignable, transferable or delegable,

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including by pledge, creation of a security interest, or otherwise, other than by a transfer by Executive’s will or by the laws of descent and distribution. If any assignment or transfer not permitted by this Section 11(c) is attempted, the Company will have no liability to pay any amount attempted to be assigned, transferred or delegated.

12.Notices.

(a)All communications, including notices, consents, requests or approvals, required or permitted to be given under this Agreement must be in writing.

(b)All notices must be provided by:

(1)hand delivery (deemed provided when delivered);

(2)electronic facsimile transmission, with verbal confirmation of receipt (deemed provided when transmitted);

(3)United States registered or certified mail, return receipt requested, postage prepaid (deemed provided five business days after mailing); or

(4)a nationally recognized overnight courier service such as Federal Express or UPS (deemed provided three business days after deposit with courier service).

(c)Notices to the Company must be addressed to the attention of the Vice President - Human Resources of the Company at the Company’s principal executive office.

(d)Notices to the Executive must be addressed to the Executive at the Executive’s principal residence.

(e)The Company or the Executive can change the address to which notices to that party are to be addressed by providing notice to the other party as required under this Section 12, except that notices of changes of address are effective only upon actual receipt.

13.Governing Law. The validity, interpretation, construction and performance of this Agreement will be governed by and construed in accordance with the substantive laws of the State of Michigan, without giving effect to its principles of conflict of laws.

14.Validity. If any provision of this Agreement or the application of any provision to any person or circumstances is held invalid, unenforceable or otherwise illegal by a court of competent jurisdiction, the remainder of this Agreement and the application of the provision to any other person or circumstances will not be affected. The provision held to be invalid, unenforceable or otherwise illegal will be amended to the minimum extent necessary to make it enforceable, valid or legal.

15.Miscellaneous.

(a)No provision of this Agreement may be modified, waived or discharged unless the waiver, modification or discharge is agreed to in writing signed by the Executive and the Company.

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(b)No waiver by either party at the time of any breach by the other party or compliance with any condition or provision of this Agreement to be performed by the other party will be a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

(c)No agreements or representations, oral or otherwise, expressed or implied, with respect to the subject matter of this Agreement have been made by either party which are not set forth expressly in this Agreement.

(d)References to Sections are to references to Sections of this Agreement.

16.Prior Agreements. As of the Effective Date, this Agreement supersedes and replaces all prior change-in-control severance agreements and similar agreements between the Executive and the Company or any of its Subsidiaries (“Prior Agreements”). All Prior Agreements cease to be of force and effect as of the Effective Date.

17.Counterparts. This Agreement may be executed in one or more counterparts, each of which is deemed an original but all of which together will constitute one agreement.

18.Definitions. For purposes of this Agreement, the following definitions apply:

(a)Agreement Expiration Date is the later of:

(1)the day before the third anniversary of the Effective Date; or

(2)the last day of any extension of the Agreement under this Section 18(a).

Beginning onthe first anniversary of the Effective Date and on each subsequent anniversary of the Effective Date, this Agreement will automatically be extended for an additional year unless, not later than 90 days preceding any anniversary of the Effective Date:

(3)the Company gives notice that it does not wish to have the Term extended; or

(4)the Com-pany gives notice that it wishes the Term to be extended for a period of less than one year, in which case the term of the Agreement will automatically be extended for the shorter period and will then terminate if not further extended by written agreement between the Company and the Executive.

(b)Annual Bonus is the aggregate annual bonus to which the Executive would have been entitled under the DTE Energy Company Annual Incentive Plan, a Subsidiary’s annual incentive plan, or any successor annual incentive plan (an “Annual Plan”) in the applicable year, presuming that the Executive’s individual performance multiplier is 100%. If the Executive participates in an Annual Plan without a specified target, the Executive’s Annual Bonus is 1/3 of the sum of the Executive’s payments under the Annual Plan for the three years preceding the applicable year (even if the Executive has not participated in the plan for three years).

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(c)Base Pay is the Executive’s annual base salary (prior to any pre-tax deferrals made under any employee benefit plans of the Company) in effect immediately prior to the Change-in-Control or immediately prior to the Executive’s Termination Date, if higher.

(d)Benefit Continuation Period is the shorter of:

(1)the two-year period beginning on the Executive’s Termination Date; or

(2)the period beginning on the Executive’s Termination Date and ending on the date the Executive attains age 65.

(e)Board is the Board of Directors of the Company.

(f)Cause. The Executive’s employment will be considered terminated for Cause if prior to termination of the Executive’s employment, the Board reasonably determines, based on a preponderance of the evidence reasonably available to the Board as of the date the Board adopts the resolution described below, that the Executive committed or engaged in:

(1)an intentional act of fraud, embezzlement or theft at a level that constitutes a felony in connection with the Executive’s duties or in the course of the Executive’s employment with the Company or a Subsidiary, whether or not the Executive is convicted or pleads guilty or nolo contender (no contest) to any related criminal charges;

(2)intentional wrongful damage to property of the Company or a Subsidiary;

(3)intentional wrongful disclosure of secret processes or confidential information of the Company or a Subsidiary;

(4)intentional wrongful engagement in any Competitive Activity;

(5)willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company that is not cured within 30 days after the Board delivers to the Executive a written demand for substantial performance specifically identifying the Executive’s failure to perform; or

(6)other intentional activity, including but not limited to a breach of the Executive’s fiduciary duties with respect to the Company, a Subsidiary, or any welfare plan or pension plan sponsored by the Company or a Subsidiary;

which, in the reasonable judgment of the Board and based on a preponderance of the evidence available to the Board is significantly detrimental to the reputa-tion, goodwill or business of the Company or significantly disrupts the workplace environment or operation of the Company’s business or administrative activities.

For pur-poses of this Agreement, no act or failure to act on the part of the Executive will be deemed “intentional” if it was due primarily to an error in the Executive’s judgment or the

11

Executive’s negligence. An act will be deemed “intentional” only if done or omitted to be done by the Executive not in good faith and without reasonable belief that the Executive’s action or omission was in the best interest of the Company.

For purposes of this Agreement, the Executive has not been terminated for Cause unless and until:

(7)a meeting of the Board is called and held for the purpose of determining if the Executive is to be terminated for Cause; and

(8)the Executive is given reasonable notice of the meeting and an opportunity to be heard before the Board, with Executive’s counsel if Executive so chooses; and

(9)at that meeting the Board finds, in the good faith opinion of the Board, that the Executive has committed an act entitling the Board to terminate the Executive’s employment for Cause; and

(10)the Executive has been provided a copy of the resolution duly adopted at that meeting by the affirmative vote of not less than three-quarters of the Board then in office and specifying in detail the particulars of the Board’s finding.

The Executive and the Executive’s beneficiaries retain the right to contest the validity or propriety of the Board’s determination that the Executive’s employment has been terminated for Cause.

(g)Change-in-Control occurs if any of the following events occurs during the Term of this Agreement:

(1)The Company is merged, consolidated or reorganized into or with another corporation or other legal person, and as a result of the merger, consolidation or reorganization less than 55% of the combined voting power of the then-outstanding Voting Stock of the other corporation or person immediately after the transaction is held in the aggregate by the holders of Voting Stock of the Company immediately prior to the transaction;

(2)The Company sells or otherwise transfers all or substantially all of its assets to another corporation or other legal person, and as a result of the sale or transfer less than 55% of the combined voting power of the then-outstanding Voting Stock of the acquiring corporation or person immediately after the sale or transfer is held in the aggregate (directly or through ownership of Voting Stock of the Company or a Subsidiary) by the holders of Voting Stock of the Company immediately prior to the sale or transfer;

(3)A report is filed on Schedule 13D or Schedule 14D-1 (or any successor schedule, form or report) under the Exchange Act disclosing that any person (as the term “person” is used in Section 13(d)(3) or Section 14(d)(2) of the Exchange Act) has become the beneficial owner (as the term “beneficial owner” is defined under

12

Rule 13d-3 or any successor rule or regulation promulgated under the Exchange Act) of securities representing 20% or more of the combined voting power of the then-outstanding Voting Stock of the Company. However, unless other-wise determined by majority vote of the Board, a Change-in-Control does not occur solely because (A) the Company, (B) a Subsidiary, or (C) any Company-sponsored employee stock ownership plan or any other employee benefit plan of the Company or a Subsidiary either files or becomes obligated to file a report or a proxy statement under or in response to Schedule 13D or Schedule 14D-l disclosing beneficial ownership by it of shares of Voting Stock, whether in excess of 20% or otherwise;

(4)During a period of two consecutive years, individuals who at the beginning of the period constitute the Directors of the Company cease for any reason to constitute at least a majority of the Directors of the Company. However, for purposes of this clause, each Director who is first elected, or first nominated for election by the Company’s stockholders, by a vote of at least two-thirds of the Directors of the Company (or of a committee of the Board) then still in office who were Directors of the Company at the beginning of the period will be deemed to have been a Director of the Company at the beginning of the period;

(5)Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company; or

(6)Execution by the Company, at the direction of the Board, of one or more definitive agreements with another corporation or other legal person to engage in a transaction that will result in a Change-in-Control described in paragraphs (1) through (5) of this Section 18(g).

(h)Code is the Internal Revenue Code of 1986, as amended.

(i)Competitive Activity is the Executive’s direct employment, without the written consent of the Board (or any Committee of the Board to which the Board delegates its authority under this Section 18(i) in writing), in any business or enterprise (including the Executive’s own business or enterprise) if:

(1)the business or enterprise engages in substantial and direct competition with the Company or any of its Subsidiaries in any state in which the Company or Subsidiary was engaged in business or actively negotiating to enter business on the Termination Date; and

(2)the business’s or enterprise’s sales of any product or service competitive with any product or service of the Company or any of its Subsidiaries amounted to 10% of the business’s or enterprise’s net sales for its most recently completed fiscal year; and

(3)the Company’s or Subsidiary’s net sales of the competitive product or service amounted to 10% of the Company’s or Subsidiary’s net sales for its most recently completed fiscal year; and

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(4)the Board determines the Executive’s employment in the business or enterprise is detrimental to the Company or any of its Subsidiaries.

“Competitive Activity” does not include the mere ownership of not more than 10% of the total combined voting power or aggregate value of all classes of stock or other securities in the enterprise and the Executive’s exercise of rights resulting from ownership of the stock.

The Board (or its delegate) has sole discretion and authority to determine if the Executive is engaging in Competitive Activity for purposes of this Agreement.

It is the Executive’s responsibility to provide information sufficient for the Board (or its delegate) to make these determinations.

(j)Employee Benefits are the perquisites, benefits and service credit for benefits provided under all employee retirement income and welfare benefit policies, plans, programs or arrangements in which Executive is entitled to participate, including without limitation any stock option, stock purchase, stock appreciation, savings, pension, supplemental executive retirement, or other retirement income or welfare benefit, deferred compensation, incentive compensation, group or other life, health, medical/hospital or other insurance (whether funded by actual insurance or self-insured by the Company or a Subsidiary), disability, salary continuation, expense reimbursement and other employee benefit policies, plans, programs or arrangements that may now exist or any equivalent successor policies, plans, programs or arrangements that may be adopted hereafter by the Company or a Subsidiary, providing perquisites, benefits and service credit for benefits at least as great in the aggregate as are payable prior to a Change-in-Control.

(k)ERISA is the Employee Retirement Income Security Act of 1974, as amended.

(l)Exchange Act is the Securities Exchange Act of 1934, as amended.

(m)Good Reason. An Executive terminates employment for Good Reason if the Executive terminates his or her employment during the Severance Period following the occurrence of any of the following events during the Severance Period:

(1)failure to elect or reelect to the office, or otherwise maintain the Executive in a position within the same or higher Executive Grouping Level (as in existence prior to the Change-in-Control) with the Company and/or a Subsidiary, as applicable, which the Executive held immediately prior to the Change-in-Control, or the removal of the Executive as Chairman of the Company (or any successor to the Company) if the Executive was Chairman of the Company immediately prior to the Change-in-Control;

(2)a significant adverse change in the nature or scope of the authorities, powers, functions, responsibilities or duties attached to the position with the Company and its Subsidiaries as compared to other executives in the same Executive Grouping

14

Level within the Company or the Subsidiary which the Executive held immediately prior to the Change-in-Control;

(3)a reduction in the Executive’s Base Pay or the opportunity to earn Incentive Pay from the Company, its Subsidiaries or the failure to pay the Executive Base Pay or Incentive Pay earned when due;

(4)the termination or denial of the Executive’s rights to Employee Benefits or a material reduction in the aggregate scope or value of Employee Benefits (unless, in the case of Welfare Benefits or Pension Benefits the termination, denial or reduction applies to all similarly situated employees of the Company and its Subsidiaries), any of which is not remedied by the Company within 10 calendar days after the Company receives written notice from the Executive of the change, reduction or termination;

(5)the liquidation, dissolution, merger, consolidation or legal reorganization of the Company or transfer of all or substantially all of its business or assets, or both, unless the successor or successors (by liquidation, merger, consolidation, reorganization, transfer or otherwise) to which all or substantially all of its business or assets, or both, have been transferred (directly or by operation of law) assumes all duties and obligations of the Company under this Agreement under Section 1l(a);

(6)without the Executive’s prior written consent, the Company:

(A)requires the Executive to change the Executive’s principal location of work to any location that is in excess of 300 miles from the location immediately prior to the Change-in-Control;

or

(B)requires the Executive to travel away from the Executive’s office in the course of discharging the Executive’s responsibilities or duties at least 40% more (in terms of aggregate days in any calendar year or in any calendar quarter when annualized for purposes of comparison to any prior year) than the average number of travel days per calendar year that was required of Executive in the three full calendar years immediately prior to the Change-in-Control; or

(7)any material breach of this Agreement by the Company or its successor.

(n)Incentive Pay is the aggregate annual payments of cash or equity compensation (determined without regard to any deferral election) and annual vesting of equity compensation, in addition to Base Pay, under any bonus, incentive, profit-sharing, performance, discretionary pay or similar agreement, policy, plan, program or arrangement (whether or not funded) of the Company or a Subsidiary, or any successor, providing economic value on an aggregate basis at least as favorable to the Executive, in terms of the

15

amount of benefits, levels of coverage and performance measures and levels of required performance, as the benefits payable prior to the Change-in-Control.

(o)Qualifying Termination means:

(1)Termination of the Executive’s employment by the Company or a Subsidiary during the Severance Period other than a termination:

(A)because of the Executive’s death;

(B)because the Executive became permanently disabled within the meaning of, and began receiving disability benefits under, the Company or Subsidiary sponsored long-term disability plan in effect for, or applicable to, the Executive immediately prior to the Change-in-Control;

(C)under any mandatory retirement policy of the Company or a Subsidiary; or

(D)for Cause;

or

(2)Termination of the Executive’s employment by the Executive during the Severance Period for Good Reason, regardless of whether any other reason, other than Cause, for the Executive’s termination exists or has occurred, including other employment.

(p)Pension Benefits are benefits provided under employee pension benefit plans as defined in Section 3(2)(A) of ERISA, but excluding employee pension benefit plans described in Section 201(2) of ERISA.

(q)Severance Pay is the collective benefits provided under any agreement, policy, plan, program, or arrangement of the Company or a Subsidiary or any provision of any individual severance, employment, or other agreement between the Executive and the Company or a Subsidiary that are paid to the Executive solely because of the termination of the Executive’s employment.

(r)Severance Period resulting from a Change-in-Control described in Sections 18(g)(1) through (5) is the period beginning on the date a Change-in-Control occurs and ending on the earliest of:

(1)the second anniversary of the Change-in-Control;

(2)the Executive’s 65^th birthday; or

(3)the Executive’s death.

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The Severance Period resulting from a Change-in-Control described in Section 18(g)(6) is the period beginning on the date the Change-in-Control occurs and ending on the earliest of:

(4)the second anniversary of the Change-in-Control;

(5)the Executive’s 65^th birthday;

(6)the Executive’s death; or

(7)the date the transaction is abandoned, as determined by the Board in a resolution adopted in good faith.

(s)Subsidiary is an entity in which the Company directly or indirectly beneficially owns 50% or more of the outstanding Voting Stock.

(t)Termination Date is the date on which the Executive’s employment is terminated by a Qualifying Termination.

(u)Welfare Benefits are benefits provided under employee welfare benefit plans, as defined in Section 3(1) of the Employee Retirement Income Security Act of 1974, as amended.

(v)Voting Stock is securities entitled to vote generally in the election of Directors.

In witness whereof, this Agreement has been entered into by the Company and the Executive as of the Effective Date.

____________________________________    

[Executive’s Name]

DTE ENERGY COMPANY

_____________________________________

Gerard M. Anderson

Chairman & Chief Executive Officer

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EX-12.58

Exhibit 12-58

DTE Energy Company
Computation of Ratio of Earnings to Fixed Charges
	Six Months Ended		Year Ended December 31,
(Millions of Dollars)	June 30, 2014		2013			2012			2011		2010		2009
Earnings:
Pretax earnings	$	653	$	904		$	1,035		$	989	$	968	$	778
Adjustments	—		(8		)	(4		)	6		1		4
Fixed charges	227		461			463			520		567		572
Net earnings	$	880	$	1,357		$	1,494		$	1,515	$	1,536	$	1,354
Fixed Charges:
Interest expense	$	213	$	432		$	441		$	490	$	543	$	545
Adjustments	14		29			22			30		24		27
Fixed charges	$	227	$	461		$	463		$	520	$	567	$	572
Ratio of earnings to fixed charges	3.88		2.94			3.23			2.91		2.71		2.37

EX-31.91

Exhibit 31-91

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 25, 2014
Gerard M. Anderson Chairman of the Board and Chief Executive Officer of DTE Energy Company

EX-31.92

Exhibit 31-92

FORM 10-Q CERTIFICATION

I, Peter B. Oleksiak, 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/ PETER B. OLEKSIAK	Date:	July 25, 2014
Peter B. Oleksiak Senior Vice President and Chief Financial Officer of DTE Energy Company

EX-32.91

Exhibit 32-91

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, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gerard M. Anderson, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

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

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

Date:	July 25, 2014	/S/ GERARD M. ANDERSON
		Gerard M. Anderson Chairman of the Board and Chief Executive Officer of DTE Energy Company

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

EX-32.92

Exhibit 32-92

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, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter B. Oleksiak, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

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

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

Date:	July 25, 2014	/S/ PETER B. OLEKSIAK
		Peter B. Oleksiak Senior Vice President and Chief Financial Officer of DTE Energy Company

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

XML

Significant Accounting Policies (Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	$ 176	$ 179
Less: Accumulated Amortization	51	45
Intangible Assets, Net	125	134
Less current intangible assets	13	12
Finite-Lived Intangible Assets, Net	112	122
Emission Allowances [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	2	2
Renewable Energy Credits [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	51	51
Contract Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets, Gross	$ 123	$ 126

XML

Financial and Other Derivative Instruments (Cumulative Gross Volume of Derivative Contracts Outstanding) (Details)	Jun. 30, 2014 dte.volumes
Natural Gas Commodity Contract [Member]
Derivative [Line Items]
Volume of Commodity Contracts	815,660,484
Electricity Commodity Contract [Member]
Derivative [Line Items]
Volume of Commodity Contracts	19,527,918
Oil Commodity Contract [Member]
Derivative [Line Items]
Volume of Commodity Contracts	11,592,000
Foreign currency exchange contracts [Member]
Derivative [Line Items]
Volume of Commodity Contracts	79,076,508

XML

Fair Value (Fair Value and Unrealized Gains for the Nuclear Decommissioning Trust Funds) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Nuclear decommissioning trusts	$ 1,237	$ 1,191
Unrealized Gains	239	213
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents	13	19
Nuclear Decommissioning Trust Fund [Member] | Equity securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Equity securities	762	730
Unrealized Gains	220	201
Nuclear Decommissioning Trust Fund [Member] | Debt securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Debt securities	462	442
Unrealized Gains	19	12
Nuclear Decommissioning Trust Fund [Member] | Cash and cash equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Unrealized Gains	$ 0	$ 0

XML

Stock-Based Compensation (Details Textuals) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Share-based Compensation [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	3 years 8 months 28 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 6	$ 10
Stock Option Plan Expense	0	0
Unrecognized Compensation Cost	$ 82
Weighted Average Period for unrecognized compensation cost to be recognized	1 year 5 months 24 days

XML

Financial and Other Derivative Instruments (Details Textuals) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ 1
Letters of Credit Outstanding, Amount	18	19
Cash Collateral Posted Net of Cash Collateral Received	26	12
Cash Collateral Paid or Received for Derivative Assets	5	26
Cash Collateral Paid or Received for Derivative Liabilities	7	17
Cash Collateral Received	6	13
Cash Collateral Paid	30	34
Value of Transactions Company Would Have Been Exposed to if Credit Rating Below Investment Grade	331
Derivative, Net Liability Position, Aggregate Fair Value	1,082
Collateral Already Posted, Aggregate Fair Value	962
Additional Collateral, Aggregate Fair Value	102
Credit Risk Contract [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 18

XML

Fair Value (Fair Value of Nuclear Decommissioning Trust Fund Assets) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 1,237	$ 1,191
Fermi 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	1,214	1,172
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	20	16
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 1,237	$ 1,191

XML

Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2014

Share-based Compensation [Abstract]

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

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In millions)
Stock-based compensation expense	$	16	$	35	$	50	$	63
Tax benefit	$	6	$	14	$	19	$	25
Stock-based compensation cost capitalized in property, plant and equipment	$	2	$	2	$	7	$	4

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, 2014:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at January 1, 2014	723,697		$	42.60
Exercised	(204,108	)	$	41.54
Forfeited or expired	(10,730	)	$	39.41
Options outstanding and exercisable at June 30, 2014	508,859		$	43.10	$	17

Schedule of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2014:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2014	492,329		$	53.76
Grants	156,390		$	69.95
Forfeitures	(13,764	)	$	62.25
Vested and issued	(216,103	)	$	47.58
Balance at June 30, 2014	418,852		$	62.71

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. Awards granted in 2014 were primarily deemed to be equity awards. The stock price and number of probable shares attributable to market conditions for such equity awards are fair valued only at the grant date. Performance shares awarded prior to 2014 are liability awards and are remeasured to fair value at each reporting period.

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2014:

	Performance Shares		Weighted Average Grant Date Fair Value
Balance at January 1, 2014	1,608,789		$	—
Grants	532,585		$	69.16
Forfeitures	(27,390	)	$	69.10
Payouts	(571,177	)	$	—
Balance at June 30, 2014	1,542,807		$	69.17

XML

Segment Information (Details Textuals)	Jun. 30, 2014 customers
Segment Reporting [Abstract]
Number of Electric Customers	2,100,000
Number of Gas Customers	1,200,000
Number of Citizens Gas Customers	17,000

XML

Regulatory Matters (Details Textuals) (Electric [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Jan. 02, 2014	Sep. 30, 2012	Jul. 30, 2012
Electric [Member]
Regulatory Asset and Liability [Line Items]
Defer the Reversal of RDM Liability				$ 127
Monthly Amount to Amortize from Liability to Income			10.6
PSCR Under-Recovery from Two Plan Years Prior	87
PSCR under-recovery from Three Plan Years Prior	148
Fermi 2 Production Level of Full Capacity					68.00%
Maximum of challenged Fermi 2 outage charges		$ 32

XML

Segment Information (Financial Data - Operating Revenues including inter segment revenues) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	$ 2,698	$ 2,225	$ 6,628	$ 4,741
Operating Segments [Member] | Electric [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	1,279	1,265	2,691	2,484
Operating Segments [Member] | Gas [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	229	248	1,033	852
Operating Segments [Member] | Gas Storage and Pipelines [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	45	31	97	58
Operating Segments [Member] | Power and Industrial Projects [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	523	429	1,098	919
Operating Segments [Member] | Energy Trading [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	819	451	2,133	844
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating Revenues	1	1	1	1
Intersegment Eliminations [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	(198)	(200)	(425)	(417)
Intersegment Eliminations [Member] | Electric [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	(7)	(7)	(14)	(13)
Intersegment Eliminations [Member] | Gas [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	(2)	(1)	(4)	(2)
Intersegment Eliminations [Member] | Gas Storage and Pipelines [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	(7)	(2)	(8)	(4)
Intersegment Eliminations [Member] | Power and Industrial Projects [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	(176)	(185)	(382)	(390)
Intersegment Eliminations [Member] | Energy Trading [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	(7)	(12)	(16)	(23)
Intersegment Eliminations [Member] | Corporate and Other [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Inter-segment Revenues	$ 1	$ 7	$ (1)	$ 15

XML

Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014
	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, 2014	$	(4	)	$	(6	)	$	(126	)	$	(1	)	$	(137	)
Other comprehensive income before reclassifications	—			1			—			1			2
Amounts reclassified from accumulated other comprehensive income	—			—			1			—			1
Net current-period other comprehensive income	—			1			1			1			3
Ending balance, June 30, 2014	$	(4	)	$	(5	)	$	(125	)	$	—		$	(134	)

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Six Months Ended June 30, 2014
	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, 2013	$	(4	)	$	(6	)	$	(126	)	$	—	$	(136	)
Other comprehensive income before reclassifications	—			1			(2		)	—		(1		)
Amounts reclassified from accumulated other comprehensive income	—			—			3			—		3
Net current-period other comprehensive income	—			1			1			—		2
Ending balance, June 30, 2014	$	(4	)	$	(5	)	$	(125	)	$	—	$	(134	)

______________________________________

(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 and other postretirement benefits cost (see Note 12).

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,
	2014		2013
	(In millions)
Emission allowances	$	2	$	2
Renewable energy credits	51		51
Contract intangible assets	123		126
	176		179
Less accumulated amortization	51		45
Intangible assets, net	125		134
Less current intangible assets	13		12
	$	112	$	122

XML

Financial and Other Derivative Instruments (Fair Value of Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	$ 909	$ 833
Derivative Liability Fair Value Gross Liability	(964)	(936)
Derivative Assets, Current	98	99
Derivative Assets, Noncurrent	26	27
Derivative Liabilities, Current	(148)	(195)
Derivative Liabilities, Noncurrent	(29)	(43)
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives designated as hedging instruments:
Derivative Assets, Current	778	691
Derivative Assets, Noncurrent	131	142
Derivative Liabilities, Current	(830)	(773)
Derivative Liabilities, Noncurrent	(134)	(163)
Natural Gas Commodity Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	271	396
Derivative Liability Fair Value Gross Liability	(318)	(503)
Electricity Commodity Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	593	400
Derivative Liability Fair Value Gross Liability	(606)	(398)
Other Commodity Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	45	37
Derivative Liability Fair Value Gross Liability	(39)	(34)
Not Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	909	833
Derivative Liability Fair Value Gross Liability	(964)	(936)
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)	(1)
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	271	396
Derivative Liability Fair Value Gross Liability	(318)	(503)
Not Designated as Hedging Instrument [Member] | Electricity Commodity Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	593	400
Derivative Liability Fair Value Gross Liability	(606)	(398)
Not Designated as Hedging Instrument [Member] | Other Commodity Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset, Fair Value, Gross Asset	45	37
Derivative Liability Fair Value Gross Liability	$ (39)	$ (34)

XML

Fair Value (Reconciliation of Level 3 Assets and Liabilities at Fair Value on a Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	$ (43)	$ (41)	$ (36)	$ (13)
Transfers into Level 3	0	0	0	0
Transfer out of Level 3	0	0	0	(2)
Total gains (losses): [Abstract]
Included in earnings	(39)	15	(19)	15
Recorded in regulatory assets/liabilities	7	3	11	4
Purchases issuances and settlements [Abstract]
Purchases			0	1
Issuances	(1)	0	(2)	0
Settlements	36	7	6	(21)
Ending Balance	(40)	(16)	(40)	(16)
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	(10)	31	(30)	20
Natural Gas Commodity Contract [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	(10)	(34)	(52)	(38)
Transfers into Level 3	0	0	0	0
Transfer out of Level 3	0	0	0	(2)
Total gains (losses): [Abstract]
Included in earnings	(16)	(2)	(38)	(10)
Recorded in regulatory assets/liabilities	0	0	0	0
Purchases issuances and settlements [Abstract]
Purchases			0	0
Issuances	0	0	0	0
Settlements	6	6	70	20
Ending Balance	(20)	(30)	(20)	(30)
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	(11)	(1)	(11)	(6)
Electricity Commodity Contract [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	(34)	(9)	13	23
Transfers into Level 3	0	0	0	0
Transfer out of Level 3	0	0	0	0
Total gains (losses): [Abstract]
Included in earnings	(22)	18	20	26
Recorded in regulatory assets/liabilities	0	0	0	0
Purchases issuances and settlements [Abstract]
Purchases			0	1
Issuances	(1)	0	(2)	0
Settlements	30	3	(58)	(38)
Ending Balance	(27)	12	(27)	12
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	33	(19)	27
Other Commodity Contract [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance	1	2	3	2
Transfers into Level 3	0	0	0	0
Transfer out of Level 3	0	0	0	0
Total gains (losses): [Abstract]
Included in earnings	(1)	(1)	(1)	(1)
Recorded in regulatory assets/liabilities	7	3	11	4
Purchases issuances and settlements [Abstract]
Purchases			0	0
Issuances	0	0	0	0
Settlements	0	(2)	(6)	(3)
Ending Balance	7	2	7	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	$ 0	$ (1)	$ 0	$ (1)

XML

Organization and Basis of Presentation (Details Textuals) (USD $) In Millions, unless otherwise specified		6 Months Ended
	Jun. 30, 2014 customers	Jun. 30, 2013 Proceeds from sale of nuclear decommissioning trust funds [Member]	Jun. 30, 2013 Investment in nuclear decommissioning trust funds [Member]
Number of Electric Customers	2,100,000
Number of Gas Customers	1,200,000
Prior Period Reclassification Adjustment		$ 282	$ (282)
Significant Potential Exposure to Loss Due to VIE Long-Term Purchase Contracts	$ 0

XML

Financial and Other Derivative Instruments Financial and Other Derivative Instruments (Netting Offsets Reconciliation to Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative Assets, Current	$ 98	$ 99
Derivative Assets, Noncurrent	26	27
Derivative Liabilities, Current	(148)	(195)
Derivative Liabilities, Noncurrent	(29)	(43)
Derivative Asset [Member]
Derivative [Line Items]
Derivative Assets, Current	778	691
Derivative Assets, Noncurrent	131	142
Derivative Liabilities [Member]
Derivative [Line Items]
Derivative Liabilities, Current	(830)	(773)
Derivative Liabilities, Noncurrent	(134)	(163)
Counterparty Netting [Member]
Derivative [Line Items]
Derivative Assets, Current	(675)	(566)
Derivative Assets, Noncurrent	(105)	(115)
Derivative Liabilities, Current	675	566
Derivative Liabilities, Noncurrent	105	115
Collateral Adjustment [Member]
Derivative [Line Items]
Derivative Assets, Current	(5)	(26)
Derivative Assets, Noncurrent	0	0
Derivative Liabilities, Current	7	12
Derivative Liabilities, Noncurrent	$ 0	$ 5

XML

Stock-Based Compensation (Components of Stock Based Compensation) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 16	$ 35	$ 50	$ 63
Tax benefit	6	14	19	25
Stock-based compensation cost capitalized in property, plant and equipment	$ 2	$ 2	$ 7	$ 4

XML

Long-Term Debt (Details Textuals) (Electric [Member], USD $) In Millions, unless otherwise specified					1 Months Ended
	Jun. 30, 2014 Tax Exempt Revenue Bonds [Member]	Apr. 30, 2014 Tax Exempt Revenue Bonds [Member]	Jun. 30, 2014 Final Maturity of 2025 [Member] Mortgages [Member]	Jun. 30, 2014 Final Maturity of 2044 [Member] Mortgages [Member]	Jun. 30, 2014 Final Maturity of 2015 [Member] Senior Notes [Member]	Jun. 30, 2014 Final Maturity of 2029 [Member] Tax Exempt Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount, Future Issuance			$ 350	$ 350
Future Debt Instrument, Interest Rate, Stated Percentage			3.375%	4.30%
Future Extinguishment of Debt, Amount					$ 200	$ 60
Debt Instrument, Interest Rate, Stated Percentage	4.875%	2.35%			4.80%	5.25%

XML

Fair Value (Gains and Losses and Proceeds from the Sale of Securities by the Nuclear Trust Funds) (Details) (Nuclear Decommissioning Trust Fund [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Nuclear Decommissioning Trust Fund [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Realized gains	$ 7	$ 11	$ 16	$ 19
Realized losses	(4)	(7)	(11)	(14)
Proceeds from sales of securities	$ 204	$ 173	$ 475	$ 309

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Organization and Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

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

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

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

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 2013 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 present 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, 2014.

Certain prior year balances were reclassified to match the current year’s financial statement presentation. Such revisions included an increase in the Consolidated Statements of Cash Flows line items for (i) Proceeds from sale of nuclear decommissioning trust funds, and (ii) Investment in nuclear decommissioning trust funds by $282 million for the six months ended June 30, 2013. These revisions were needed to properly state the gross purchases and sales activity in the nuclear decommissioning trust fund for the six months ended June 30, 2013. The total of Net cash used in investing activities for the six months ended June 30, 2013 was unchanged by these revisions. The revisions noted above are not deemed material, individually or in the aggregate, to the prior period consolidated financial statements.

Principles of Consolidation

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

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

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

The Company has variable interests in VIEs through certain of its long-term purchase and sale contracts. As of June 30, 2014, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase and sale contracts are predominately related to working capital accounts and generally represent the amounts owed by or to the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any significant form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase and sale contracts.

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

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

The following table summarizes the major balance sheet items for consolidated VIEs as of June 30, 2014 and December 31, 2013. All assets and liabilities of a consolidated VIE are presented where it has been determined that aconsolidated VIE has either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.

	June 30, 2014						December 31, 2013
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	14	$	14	$	—	$	12	$	12
Restricted cash	88		6		94		100		8		108
Accounts receivable	39		12		51		34		16		50
Inventories	—		27		27		—		118		118
Property, plant and equipment, net	—		86		86		—		99		99
Securitized regulatory assets	135		—		135		231		—		231
Other current and long-term assets	2		7		9		4		9		13
	$	264	$	152	$	416	$	369	$	262	$	631
LIABILITIES
Accounts payable and accrued current liabilities	$	5	$	8	$	13	$	7	$	23	$	30
Current portion long-term debt, including capital leases	201		9		210		196		9		205
Current regulatory liabilities	41		—		41		43		—		43
Mortgage bonds, notes and other	—		18		18		—		21		21
Securitization bonds	—		—		—		105		—		105
Capital lease obligations	—		4		4		—		7		7
Other current and long-term liabilities	8		5		13		8		6		14
	$	255	$	44	$	299	$	359	$	66	$	425

Amounts for non-consolidated VIEs as of June 30, 2014 and December 31, 2013 are as follows:

	June 30, 2014		December 31, 2013
	(In millions)
Other investments	$	130	$	141
Notes receivable	$	13	$	8

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Short-Term Credit Arrangements and Borrowings (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,025
Amounts Outstanding	719
Net availability	1,306
DTE Energy [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	1,425
Amounts Outstanding	444
Net availability	981
Electric [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	300
Amounts Outstanding	275
Net availability	25
Gas [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	300
Amounts Outstanding	0
Net availability	300
Letter of Credit [Member]
Availability under combined facilities
Amounts Outstanding	208
Letter of Credit [Member] | Unsecured letter of credit, expiring in February 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	100
Letter of Credit [Member] | Unsecured letter of credit facility expiring in August 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	125
Letter of Credit [Member] | DTE Energy [Member]
Availability under combined facilities
Amounts Outstanding	208
Letter of Credit [Member] | DTE Energy [Member] | Unsecured letter of credit, expiring in February 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	100
Letter of Credit [Member] | DTE Energy [Member] | Unsecured letter of credit facility expiring in August 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	125
Letter of Credit [Member] | Electric [Member]
Availability under combined facilities
Amounts Outstanding	0
Letter of Credit [Member] | Electric [Member] | Unsecured letter of credit, expiring in February 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	0
Letter of Credit [Member] | Electric [Member] | Unsecured letter of credit facility expiring in August 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	0
Letter of Credit [Member] | Gas [Member]
Availability under combined facilities
Amounts Outstanding	0
Letter of Credit [Member] | Gas [Member] | Unsecured letter of credit, expiring in February 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	0
Letter of Credit [Member] | Gas [Member] | Unsecured letter of credit facility expiring in August 2015 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	0
Revolving Credit Facility [Member] | Unsecured revolving credit facility expiring in April 2018 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	1,800
Revolving Credit Facility [Member] | DTE Energy [Member] | Unsecured revolving credit facility expiring in April 2018 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	1,200
Revolving Credit Facility [Member] | Electric [Member] | Unsecured revolving credit facility expiring in April 2018 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	300
Revolving Credit Facility [Member] | Gas [Member] | Unsecured revolving credit facility expiring in April 2018 [Member]
Availability under combined facilities
Line of Credit Facility, Maximum Borrowing Capacity	300
Commercial Paper [Member]
Availability under combined facilities
Amounts Outstanding	511
Commercial Paper [Member] | DTE Energy [Member]
Availability under combined facilities
Amounts Outstanding	236
Commercial Paper [Member] | Electric [Member]
Availability under combined facilities
Amounts Outstanding	275
Commercial Paper [Member] | Gas [Member]
Availability under combined facilities
Amounts Outstanding	$ 0

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Fair Value (Transfers between Levels of the Fair Value Hierarchy) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Fair Value Transfers Between Level 1, Level 2 and Level 3 [Line Items]
Transfers from Level 2 to Level 1	$ 0	$ 0	$ 0	$ 0
Transfers from Level 3 to Level 1	0	0	0	0
Transfers from Level 1 to Level 2	0	0	0	0
Transfers from Level 3 to Level 2	0	0	0	2
Transfers from Level 1 to Level 3	0	0	0	0
Transfers from Level 2 to Level 3	$ 0	$ 0	$ 0	$ 0

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2014

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 and six months ended June 30:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014		2013			2014		2013
	(In millions, except per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	124	$	105		$	450	$	339
Average number of common shares outstanding	177		174			177		174
Weighted average net restricted shares outstanding	—		1			—		1
Dividends declared — common shares	$	116	$	114		$	231	$	222
Dividends declared — net restricted shares	—		1			1		—
Total distributed earnings	$	116	$	115		$	232	$	222
Net income less distributed earnings	$	8	$	(10	)	$	218	$	117
Distributed (dividends per common share)	$	0.66	$	0.66		$	1.31	$	1.28
Undistributed	0.04		(0.06		)	1.23		0.66
Total Basic Earnings per Common Share	$	0.70	$	0.60		$	2.54	$	1.94
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	124	$	105		$	450	$	339
Average number of common shares outstanding	177		175			177		174
Weighted average net restricted shares outstanding	—		1			—		1
Dividends declared — common shares	$	116	$	114		$	231	$	222
Dividends declared — net restricted shares	—		1			1		—
Total distributed earnings	$	116	$	115		$	232	$	222
Net income less distributed earnings	$	8	$	(10	)	$	218	$	117
Distributed (dividends per common share)	$	0.66	$	0.66		$	1.31	$	1.28
Undistributed	0.04		(0.06		)	1.23		0.66
Total Diluted Earnings per Common Share	$	0.70	$	0.60		$	2.54	$	1.94

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014 follows:

	(In millions)
Asset retirement obligations at December 31, 2013	$	1,827
Accretion	56
Liabilities incurred	9
Liabilities settled	(4		)
Revision in estimated cash flows	(5		)
Asset retirement obligations at June 30, 2014	$	1,883

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	$ 1,827
Accretion	56
Liabilities Incurred	9
Liabilities Settled	(4)
Revision in estimated cash flows	(5)
Asset retirement obligations	$ 1,883

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Fair Value (Unobservable Inputs related to Level 3 Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014 MMBTU	Dec. 31, 2013 MMBTU
Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Weighted Average Forward Basis Price	(0.11)	(0.16)
Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Weighted Average Forward Basis Price	4	3
Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Forward basis price	(0.80)	(0.88)
Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Forward basis price	(3)	(7)
Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Forward basis price	6.98	5.07
Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Forward basis price	16	15
Fair Value, Measurements, Recurring [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	$ 124	$ 126
Derivative Liabilities	(177)	(238)
Fair Value, Measurements, Recurring [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	12	14
Derivative Liabilities	(54)	(108)
Fair Value, Measurements, Recurring [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	106	109
Derivative Liabilities	(122)	(129)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	154	176
Derivative Liabilities	(194)	(212)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	52	34
Derivative Liabilities	(72)	(86)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Unobservable Inputs Valuation Techniques [Line Items]
Derivative Assets	95	139
Derivative Liabilities	$ (122)	$ (126)

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2014

Long-term Debt, Unclassified [Abstract]

Schedule of Issued Debt [Table Text Block]

In 2014, the following debt was issued:

Company	Month	Type	Interest Rate	Maturity	Amount
					(In millions)
DTE Energy	May	Senior Notes (a)	3.50%	2024	$	350
DTE Electric	June	Mortgage Bonds (a)	3.77%	2026	100
DTE Electric	June	Mortgage Bonds (a)	4.60%	2044	150
					$	600

_______________________________________

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

Schedule of Extinguishment of Debt [Table Text Block]

In 2014, the following debt was redeemed:

Company	Month	Type	Interest Rate	Maturity	Amount
					(In millions)
DTE Electric	March	Mortgage Bonds	Various	2014	$	13
DTE Electric	March	Securitization Bonds	6.62%	2014	100
DTE Electric	April	Tax Exempt Revenue Bonds (a)	2.35%	2024	31
DTE Electric	April	Tax Exempt Revenue Bonds (a)	4.65%	2028	32
DTE Gas	May	Mortgage Bonds	8.25%	2014	80
DTE Energy	May	Senior Notes	7.625%	2014	300
DTE Electric	June	Tax Exempt Revenue Bonds (a)	4.875%	2029	36
DTE Electric	June	Tax Exempt Revenue Bonds (a)	6.00%	2036	69
DTE Energy	Various	Other Long Term Debt	Various	2014	3
					$	664

_______________________________________

(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 Tax Exempt Revenue Bonds.

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Short-Term Credit Arrangements and Borrowings (Tables)

6 Months Ended

Jun. 30, 2014

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The availability under the facilities in place at June 30, 2014 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in February 2015	$	100	$	—	$	—	$	100
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,425		300		300		2,025
Amounts outstanding at June 30, 2014:
Commercial paper issuances	236		275		—		511
Letters of credit	208		—		—		208
	444		275		—		719
Net availability at June 30, 2014	$	981	$	25	$	300	$	1,306

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Consolidated Statements of Changes in Equity (Unaudited) (USD $) In Millions, except Share data	Total	Common Stock	Retained Earnings	Non-controlling Interest	Accumulated Other Comprehensive Loss	Accumulated Defined Benefit Plans Adjustment [Member]	Accumulated Net Unrealized Investment Gain (Loss) [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling interest at Dec. 31, 2013	$ 7,954	$ 3,907	$ 4,150	$ 33	$ (136)
Beginning Balance, shares at Dec. 31, 2013	177,087,230	177,087,000
Net Income	453		450	3
Dividends declared on common stock	(354)		(354)
Repurchase of common stock, Shares		(713,000)
Repurchase of common stock, Value	(52)	(52)
Other Comprehensive Income (Loss), Net of Tax	2					1	1
Stock-based compensation, distributions to noncontrolling interests and other, shares		619,000
Stock-based compensation, distributions to noncontrolling interests and other	23	41		(18)
Stockholders' Equity, Including Portion Attributable to Noncontrolling interest at Jun. 30, 2014	8,026	3,896	4,246	18	(134)
Ending Balance, shares at Jun. 30, 2014	176,993,343	176,993,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling interest at Mar. 31, 2014
Net Income	126
Other Comprehensive Income (Loss), Net of Tax	3					1	1
Stockholders' Equity, Including Portion Attributable to Noncontrolling interest at Jun. 30, 2014	$ 8,026				$ (134)
Ending Balance, shares at Jun. 30, 2014	176,993,343

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Retirement Benefits and Trusteed Assets (Tables)

6 Months Ended

Jun. 30, 2014

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 Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Three Months Ended June 30	(In millions)
Service cost	$	22		$	25		$	9		$	12
Interest cost	52			47			22			21
Expected return on plan assets	(68		)	(66		)	(30		)	(27		)
Amortization of:
Net actuarial loss	38			50			6			15
Prior service credit	—			—			(36		)	(36		)
Net periodic benefit cost (credit)	$	44		$	56		$	(29	)	$	(15	)

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Six Months Ended June 30	(In millions)
Service cost	$	43		$	49		$	18		$	28
Interest cost	105			95			45			45
Expected return on plan assets	(136		)	(133		)	(61		)	(54		)
Amortization of:
Net actuarial loss	76			101			11			32
Prior service credit	—			—			(72		)	(59		)
Net periodic benefit cost (credit)	$	88		$	112		$	(59	)	$	(8	)

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Significant Accounting Policies (Details Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Significant Accounting Policies [Line Items]
Other Nonoperating Income	$ 40	$ 46	$ 81	$ 90
Effective Income Tax Rate, Continuing Operations	28.00%	29.00%	31.00%	30.00%
Other Information Pertaining to Income Taxes			The 1% decrease in the effective tax rate for the three months ended June 30, 2014 is due to higher production tax credits. The 1% increase in effective tax rate for the six months ended June 30, 2014 is due to $8 million of deferred tax expense resulting from New York state income tax reform enacted on March 31, 2014, partially offset by higher production tax credits.
Unrecognized Tax Benefits that would impact Effective Tax Rate	2		2
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecognized Benefit	1		1
Minimum [Member]
Significant Accounting Policies [Line Items]
Finite Lived Asset Useful Life			1 year
Maximum [Member]
Significant Accounting Policies [Line Items]
Finite Lived Asset Useful Life			28 years
Power and Industrial Projects [Member]
Significant Accounting Policies [Line Items]
Other Nonoperating Income	$ 15	$ 20	$ 32	$ 35

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Financial and Other Derivative Instruments (Effect of Derviatives not Designated as Hedging Instruments on the Consolidated Statement of Operations) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 101	$ 8	$ 122	$ 33
Foreign currency exchange contracts [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3	(1)	(1)	(1)
Natural Gas Commodity Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	155	46	28	36
Natural Gas Commodity Contract [Member] | Fuel, purchased power and gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(9)	(46)	11	(32)
Electricity Commodity Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(45)	10	88	30
Other Commodity Contract [Member] | Operating Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (3)	$ (1)	$ (4)	$ 0

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Segment Information (Financial Data - Net Income or Loss) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	$ 124	$ 105	$ 450	$ 339
Electric [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	129	89	265	204
Gas [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	(4)	8	125	104
Gas Storage and Pipelines [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	18	16	39	33
Power and Industrial Projects [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	13	7	28	19
Energy Trading [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	(14)	(2)	28	5
Corporate and Other [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net Income (Loss) Attributable to Parent	$ (18)	$ (13)	$ (35)	$ (26)

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Consolidated Statements of Operations (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating Revenues	$ 2,698	$ 2,225	$ 6,628	$ 4,741
Operating Expenses
Fuel, purchased power and gas	1,276	940	3,431	1,964
Operation and maintenance	811	705	1,652	1,440
Depreciation, depletion and amortization	282	268	562	527
Taxes other than income	87	84	182	178
Asset (gains) and losses, reserves and impairments, net	(7)	5	(8)	(1)
Total operating expenses	2,449	2,002	5,819	4,108
Operating Income	249	223	809	633
Other (Income) and Deductions
Interest expense	106	112	216	221
Interest income	(3)	(3)	(5)	(5)
Other income	(40)	(46)	(81)	(90)
Other expenses	10	9	18	16
Total Other (Income) and Deductions	73	72	148	142
Income Before Income Taxes	176	151	661	491
Income Tax Expense	50	44	208	149
Net Income	126	107	453	342
Less: Net Income Attributable to Noncontrolling Interests	2	2	3	3
Net Income Attributable to DTE Energy Company	$ 124	$ 105	$ 450	$ 339
Basic Earnings per Common Share
Total Basic Earnings per Common Share	$ 0.70	$ 0.60	$ 2.54	$ 1.94
Diluted Earnings per Common Share
Total Diluted Earnings per Common Share	$ 0.70	$ 0.60	$ 2.54	$ 1.94
Weighted Average Common Shares Outstanding
Basic	177	174	177	174
Diluted	177	175	177	174
Dividends Declared per Common Share	$ 0.66	$ 0.66	$ 1.31	$ 1.28

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Fair Value (Fair Value of Financial Instruments) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Fair Value of Financial Instruments [Line Items]
Notes Receivable, Excluding Capital Leases	$ 46	$ 41
Dividends payable	238	116
Short-term Debt	511	131
Long-term Debt, excluding capital leases	8,030	8,094
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, excluding capital leases, Fair Value	0	0
Dividends Payable Fair Value	238	116
Short-term Debt, Fair Value	0	0
Long-term Debt, excluding capital leases, Fair Value	483	425
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, excluding capital leases, Fair Value	0	0
Dividends Payable Fair Value	0	0
Short-term Debt, Fair Value	511	131
Long-term Debt, excluding capital leases, Fair Value	7,511	7,551
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments [Line Items]
Notes Receivable, excluding capital leases, Fair Value	46	41
Dividends Payable Fair Value	0	0
Short-term Debt, Fair Value	0	0
Long-term Debt, excluding capital leases, Fair Value	$ 801	$ 499

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Consolidated Statements of Financial Position (Unaudited) (Parenthetical) (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current Assets:
Allowance for doubtful accounts	$ 60	$ 55
Stockholders' Equity:
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	176,993,343	177,087,230
Common stock, shares outstanding	176,993,343	177,087,230

XML

Long-Term Debt Long-Term Debt (Debt Issuances) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	May 31, 2014 DTE Energy [Member] Senior Notes [Member]	May 31, 2014 DTE Energy [Member] Ten Years [Member] Senior Notes [Member]	Jun. 30, 2014 Electric [Member] Twelve Years [Member] Mortgages [Member]	Jun. 30, 2014 Electric [Member] Thirty Years [Member] Mortgages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.625%	3.50%	3.77%	4.60%
Debt Instrument, Face Amount	$ 600		$ 350	$ 100	$ 150

XML

Organization and Basis of Presentation (Consolidated Variable Interest Entities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
Assets [Abstract]
Cash and cash equivalents	$ 75	$ 52	$ 46	$ 65
Restricted cash	110	123
Accounts receivable	1,400	1,542
Property, plant and equipment, net	16,307	15,800
Securitized regulatory assets	135	231
Total Assets	26,189	25,935
Liabilities [Abstract]
Current portion long-term debt, including, capital leases	229	898
Current regulatory liabilities	150	302
Mortgage bonds, notes and other	7,329	6,618
Securitization bonds	0	105
Capital lease obligations	4	11
Variable Interest Entity, Primary Beneficiary Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	88	100
Accounts receivable	39	34
Inventories	0	0
Property, plant and equipment, net	0	0
Securitized regulatory assets	135	231
Other current and long-term assets	2	4
Total Assets	264	369
Liabilities [Abstract]
Accounts payable and accrued current liabilities	5	7
Current portion long-term debt, including, capital leases	201	196
Current regulatory liabilities	41	43
Mortgage bonds, notes and other	0	0
Securitization bonds	0	105
Capital lease obligations	0	0
Other current and long-term liabilities	8	8
Total Liabilities	255	359
Variable Interest Entity, Primary Beneficiary Other [Member]
Assets [Abstract]
Cash and cash equivalents	14	12
Restricted cash	6	8
Accounts receivable	12	16
Inventories	27	118
Property, plant and equipment, net	86	99
Securitized regulatory assets	0	0
Other current and long-term assets	7	9
Total Assets	152	262
Liabilities [Abstract]
Accounts payable and accrued current liabilities	8	23
Current portion long-term debt, including, capital leases	9	9
Current regulatory liabilities	0	0
Mortgage bonds, notes and other	18	21
Securitization bonds	0	0
Capital lease obligations	4	7
Other current and long-term liabilities	5	6
Total Liabilities	44	66
Variable Interest Entity, Primary Beneficiary [Member]
Assets [Abstract]
Cash and cash equivalents	14	12
Restricted cash	94	108
Accounts receivable	51	50
Inventories	27	118
Property, plant and equipment, net	86	99
Securitized regulatory assets	135	231
Other current and long-term assets	9	13
Total Assets	416	631
Liabilities [Abstract]
Accounts payable and accrued current liabilities	13	30
Current portion long-term debt, including, capital leases	210	205
Current regulatory liabilities	41	43
Mortgage bonds, notes and other	18	21
Securitization bonds	0	105
Capital lease obligations	4	7
Other current and long-term liabilities	13	14
Total Liabilities	$ 299	$ 425

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Retirement Benefits and Trusteed Assets (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service Cost	$ 22	$ 25	$ 43	$ 49
Interest Cost	52	47	105	95
Expected Return on Plan Assets	(68)	(66)	(136)	(133)
Amortization of Net Actuarial Losses	38	50	76	101
Amortization of Prior Service Cost (Credit)	0	0	0	0
Net Periodic Benefit Cost (Credit)	44	56	88	112
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service Cost	9	12	18	28
Interest Cost	22	21	45	45
Expected Return on Plan Assets	(30)	(27)	(61)	(54)
Amortization of Net Actuarial Losses	6	15	11	32
Amortization of Prior Service Cost (Credit)	(36)	(36)	(72)	(59)
Net Periodic Benefit Cost (Credit)	$ (29)	$ (15)	$ (59)	$ (8)

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Segment Information (Notes)

6 Months Ended

Jun. 30, 2014

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014		2013
	(In millions)
Inter-segment Revenues
Electric	$	7		$	7		$	14	$	13
Gas	2			1			4		2
Gas Storage and Pipelines	7			2			8		4
Power and Industrial Projects	176			185			382		390
Energy Trading	7			12			16		23
Corporate and Other	(1		)	(7		)	1		(15		)
	$	198		$	200		$	425	$	417

Financial data of the business segments follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In millions)
Operating Revenues
Electric	$	1,279		$	1,265		$	2,691		$	2,484
Gas	229			248			1,033			852
Gas Storage and Pipelines	45			31			97			58
Power and Industrial Projects	523			429			1,098			919
Energy Trading	819			451			2,133			844
Corporate & Other	1			1			1			1
Reconciliation & Eliminations	(198		)	(200		)	(425		)	(417		)
Total	$	2,698		$	2,225		$	6,628		$	4,741

Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	129		$	89		$	265		$	204
Gas	(4		)	8			125			104
Gas Storage and Pipelines	18			16			39			33
Power and Industrial Projects	13			7			28			19
Energy Trading	(14		)	(2		)	28			5
Corporate & Other	(18		)	(13		)	(35		)	(26		)
Net Income Attributable to DTE Energy	$	124		$	105		$	450		$	339

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Organization and Basis of Presentation (Non Consolidated Variable Interest Entities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Notes receivable	$ 90	$ 102
Unconsolidated Variable Interest Entity [Member]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Other investments	130	141
Notes receivable	$ 13	$ 8

XML

Organization and Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2014

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

Schedule of Variable Interest Entities [Table Text Block]

The following table summarizes the major balance sheet items for consolidated VIEs as of June 30, 2014 and December 31, 2013. All assets and liabilities of a consolidated VIE are presented where it has been determined that aconsolidated VIE has either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE's obligations have been excluded from the table below.

	June 30, 2014						December 31, 2013
	Securitization		Other		Total		Securitization		Other		Total
	(In millions)
ASSETS
Cash and cash equivalents	$	—	$	14	$	14	$	—	$	12	$	12
Restricted cash	88		6		94		100		8		108
Accounts receivable	39		12		51		34		16		50
Inventories	—		27		27		—		118		118
Property, plant and equipment, net	—		86		86		—		99		99
Securitized regulatory assets	135		—		135		231		—		231
Other current and long-term assets	2		7		9		4		9		13
	$	264	$	152	$	416	$	369	$	262	$	631
LIABILITIES
Accounts payable and accrued current liabilities	$	5	$	8	$	13	$	7	$	23	$	30
Current portion long-term debt, including capital leases	201		9		210		196		9		205
Current regulatory liabilities	41		—		41		43		—		43
Mortgage bonds, notes and other	—		18		18		—		21		21
Securitization bonds	—		—		—		105		—		105
Capital lease obligations	—		4		4		—		7		7
Other current and long-term liabilities	8		5		13		8		6		14
	$	255	$	44	$	299	$	359	$	66	$	425

Summary of Amounts for Non-Consolidated Variable Interest Entities [Table Text Block]

Amounts for non-consolidated VIEs as of June 30, 2014 and December 31, 2013 are as follows:

	June 30, 2014		December 31, 2013
	(In millions)
Other investments	$	130	$	141
Notes receivable	$	13	$	8

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Stock-Based Compensation (Stock Option Activity) (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2014
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding	723,697
Exercised	(204,108)
Forfeitures or expired	(10,730)
Options outstanding	508,859
Options exercisable	508,859
Weighted Average Exercise Price Per Share - Options outstanding	$ 42.60
Weighted Average Exercise Price - Exercised	$ 41.54
Weighted Average Exercise Price Per Share - Forfeitured or expired	$ 39.41
Weighted Average Exercise Price Per Share - Options outstanding	$ 43.10
Weighted Average Exercise Price - Options exercisable	$ 43.10
Aggregate Intrinsic Value - Options outstanding	$ 17
Aggregate Intrinsic Value - Options exercisable	$ 17

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Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Operating Activities
Net Income	$ 453	$ 342
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	562	527
Nuclear fuel amortization	19	17
Allowance for equity funds used during construction	(11)	(6)
Deferred income taxes	196	123
Asset (gains) and losses, reserves and impairments, net	(7)	0
Changes in assets and liabilities:
Accounts receivable, net	145	70
Inventories	9	133
Accounts payable	104	(29)
Gas inventory equalization	38	73
Accrued pension obligation	(89)	(42)
Accrued postretirement obligation	(43)	(174)
Derivative assets and liabilities	(59)	(15)
Regulatory assets and liabilities	(224)	226
Other assets	35	71
Other liabilities	(52)	(49)
Net cash from operating activities	1,076	1,267
Investing Activities
Plant and equipment expenditures — utility	(924)	(708)
Plant and equipment expenditures — non-utility	(156)	(197)
Proceeds from sale of assets	31	15
Restricted cash for debt redemption, principally Securitization	13	10
Proceeds from sale of nuclear decommissioning trust fund assets	475	309
Investment in nuclear decommissioning trust funds	(483)	(317)
Other	(23)	(23)
Net cash used for investing activities	(1,067)	(911)
Financing Activities
Issuance of long-term debt, net of issuance costs	595	371
Redemption of long-term debt	(664)	(515)
Short-term borrowings, net	380	(24)
Issuance of common stock	0	19
Repurchase of common stock	(52)	0
Dividends on common stock	(232)	(215)
Other	(13)	(11)
Net cash from (used for) financing activities	14	(375)
Net Increase (Decrease) in Cash and Cash Equivalents	23	(19)
Cash and Cash Equivalents at Beginning of Period	52	65
Cash and Cash Equivalents at End of Period	75	46
Supplemental Disclosure of Non-Cash Information
Plant and equipment expenditures in accounts payable	$ 209	$ 218

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Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 126	$ 107	$ 453	$ 342
Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $1, $1, $1 and $2, respectively	1	2	1	5
Net unrealized gains on investments during the period, net of taxes of $—, $—, $— and $—, respectively	1	0	1	0
Foreign currency translation, net of taxes of $1, $(1), $— and $(1), respectively	1	(1)	0	(2)
Other Comprehensive Income (Loss), Net of Tax	3	1	2	3
Comprehensive income	129	108	455	345
Less: Comprehensive income attributable to noncontrolling interests	2	2	3	3
Comprehensive income attributable to DTE Energy Company	$ 127	$ 106	$ 452	$ 342

XML

Long-Term Debt (Notes)

6 Months Ended

Jun. 30, 2014

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBT

Debt Issuances

In 2014, the following debt was issued:

Company	Month	Type	Interest Rate	Maturity	Amount
					(In millions)
DTE Energy	May	Senior Notes (a)	3.50%	2024	$	350
DTE Electric	June	Mortgage Bonds (a)	3.77%	2026	100
DTE Electric	June	Mortgage Bonds (a)	4.60%	2044	150
					$	600

_______________________________________

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

In July 2014, DTE Electric issued $350 million of 3.375% mortgage bonds due 2025 and $350 million of 4.30% mortgage bonds due 2044. Proceeds will be used for redemption of DTE Electric long-term debt, for the repayment of short-term borrowings and for general corporate purposes.

Debt Redemptions

In 2014, the following debt was redeemed:

Company	Month	Type	Interest Rate	Maturity	Amount
					(In millions)
DTE Electric	March	Mortgage Bonds	Various	2014	$	13
DTE Electric	March	Securitization Bonds	6.62%	2014	100
DTE Electric	April	Tax Exempt Revenue Bonds (a)	2.35%	2024	31
DTE Electric	April	Tax Exempt Revenue Bonds (a)	4.65%	2028	32
DTE Gas	May	Mortgage Bonds	8.25%	2014	80
DTE Energy	May	Senior Notes	7.625%	2014	300
DTE Electric	June	Tax Exempt Revenue Bonds (a)	4.875%	2029	36
DTE Electric	June	Tax Exempt Revenue Bonds (a)	6.00%	2036	69
DTE Energy	Various	Other Long Term Debt	Various	2014	3
					$	664

_______________________________________

(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 Tax Exempt Revenue Bonds.

In June 2014, DTE Electric called for redemption $200 million of 4.80% senior notes due in February 2015 to be redeemed in July 2014 and $60 million of 5.25% tax exempt revenue bonds due in August 2029 to be redeemed in August 2014.

XML

DEI Document	6 Months Ended
	Jun. 30, 2014
Entity Registrant Name	DTE ENERGY CO
Entity Central Index Key	0000936340
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	176,993,343

XML

Short-Term Credit Arrangements and Borrowings (Notes)

6 Months Ended

Jun. 30, 2014

Short-term Debt [Abstract]

Short-Term Credit Arrangements and Borrowings

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, DTE Electric and DTE Gas, have unsecured revolving credit agreements 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, 2014, the total funded debt to total capitalization ratios for DTE Energy, DTE Electric and DTE Gas are 0.49 to 1, 0.52 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, 2014 is shown in the following table:

	DTE Energy		DTE Electric		DTE Gas		Total
	(In millions)
Unsecured letter of credit facility, expiring in February 2015	$	100	$	—	$	—	$	100
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring April 2018	1,200		300		300		1,800
	1,425		300		300		2,025
Amounts outstanding at June 30, 2014:
Commercial paper issuances	236		275		—		511
Letters of credit	208		—		—		208
	444		275		—		719
Net availability at June 30, 2014	$	981	$	25	$	300	$	1,306

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $36 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, 2014, a $50 million letter of credit was in place, raising the capacity under this facility to $150 million. The $50 million letter of credit is included in the table above. The amount outstanding under this agreement was $47 million and $138 million at June 30, 2014 and December 31, 2013, respectively.

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Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Benefit Plan Improvement, Tax	$ 1	$ 1	$ 1	$ 2
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	0	0	0	0
Other Comprehensive Income (Loss), Foreign Currency Translation Gain (Loss) Arising During Period, Tax	$ 1	$ (1)	$ 0	$ (1)

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Fair Value (Notes)

6 Months Ended

Jun. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Disclosure

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, 2014 and December 31, 2013. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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

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

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

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2014 and December 31, 2013:

	June 30, 2014															December 31, 2013
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	12		$	96		$	—		$	—		$	108		$	10		$	115		$	—		$	—		$	125
Nuclear decommissioning trusts	798			439			—			—			1,237			779			412			—			—			1,191
Other investments (c) (d)	94			50			—			—			144			92			44			—			—			136
Derivative assets:
Commodity Contracts:
Natural Gas	118			101			52			(259		)	12			273			89			34			(382		)	14
Electricity	—			498			95			(487		)	106			—			261			139			(291		)	109
Other	35			3			7			(39		)	6			33			1			3			(34		)	3
Total derivative assets	153			602			154			(785		)	124			306			351			176			(707		)	126
Total	$	1,057		$	1,187		$	154		$	(785	)	$	1,613		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(123	)	$	(123	)	$	(72	)	$	264		$	(54	)	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)
Electricity	—			(484		)	(122		)	484			(122		)	—			(272		)	(126		)	269			(129		)
Other	(32		)	(7		)	—			39			—			(32		)	(2		)	—			34			—
Other derivative contracts (f)	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(155		)	(615		)	(194		)	787			(177		)	(309		)	(415		)	(212		)	698			(238		)
Total	$	(155	)	$	(615	)	$	(194	)	$	787		$	(177	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	902		$	572		$	(40	)	$	2		$	1,436		$	878		$	507		$	(36	)	$	(9	)	$	1,340
Assets:
Current	$	145		$	618		$	123		$	(680	)	$	206		$	277		$	400		$	139		$	(592	)	$	224
Noncurrent (e)	912			569			31			(105		)	1,407			910			522			37			(115		)	1,354
Total Assets	$	1,057		$	1,187		$	154		$	(785	)	$	1,613		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Current	$	(133	)	$	(528	)	$	(169	)	$	682		$	(148	)	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)
Noncurrent	(22		)	(87		)	(25		)	105			(29		)	(41		)	(87		)	(35		)	120			(43		)
Total Liabilities	$	(155	)	$	(615	)	$	(194	)	$	787		$	(177	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	902		$	572		$	(40	)	$	2		$	1,436		$	878		$	507		$	(36	)	$	(9	)	$	1,340

_______________________________________

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

(b) At June 30, 2014, available-for-sale securities of $108 million included $95 million and $13 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2013, available-for-sale securities of $125 million, included $109 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available-for-sale equity securities of $7 million at both June 30, 2014 and December 31, 2013, are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $144 million and $136 million at June 30, 2014 and December 31, 2013, respectively, of other investments that are included in the Consolidated Statements of Financial Position in Other investments.

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

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of short-term investments and money market funds.

Nuclear Decommissioning Trusts and Other Investments

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

Derivative Assets and Liabilities

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30, 2014												Three Months Ended June 30, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of April 1	$	(10	)	$	(34	)	$	1		$	(43	)	$	(34	)	$	(9	)	$	2		$	(41	)
Transfers into Level 3	—			—			—			—			—			—			—			—
Transfers out of Level 3	—			—			—			—			—			—			—			—
Total gains (losses):
Included in earnings	(16		)	(22		)	(1		)	(39		)	(2		)	18			(1		)	15
Recorded in regulatory assets/liabilities	—			—			7			7			—			—			3			3
Purchases, issuances and settlements:
Issuances	—			(1		)	—			(1		)	—			—			—			—
Settlements	6			30			—			36			6			3			(2		)	7
Net Assets (Liabilities) as of June 30	$	(20	)	$	(27	)	$	7		$	(40	)	$	(30	)	$	12		$	2		$	(16	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(11	)	$	1		$	—		$	(10	)	$	(1	)	$	33		$	(1	)	$	31

	Six Months Ended June 30, 2014												Six Months Ended June 30, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of January 1	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
Transfers into Level 3	—			—			—			—			—			—			—			—
Transfers out of Level 3	—			—			—			—			(2		)	—			—			(2		)
Total gains (losses):
Included in earnings	(38		)	20			(1		)	(19		)	(10		)	26			(1		)	15
Recorded in regulatory assets/liabilities	—			—			11			11			—			—			4			4
Purchases, issuances and settlements:
Purchases	—			—			—			—			—			1			—			1
Issuances	—			(2		)	—			(2		)	—			—			—			—
Settlements	70			(58		)	(6		)	6			20			(38		)	(3		)	(21		)
Net Assets (Liabilities) as of June 30	$	(20	)	$	(27	)	$	7		$	(40	)	$	(30	)	$	12		$	2		$	(16	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(11	)	$	(19	)	$	—		$	(30	)	$	(6	)	$	27		$	(1	)	$	20

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 and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30, 2014					Three Months Ended June 30, 2013
	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		—	—		N/A

	Six Months Ended June 30, 2014					Six Months Ended June 30, 2013
	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		2
Transfers into Level 3 from	—	—		N/A		—	—		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of June 30, 2014:

	June 30, 2014
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	52	$	(72	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.80	)	—	$	6.98	/MMBtu	$	(0.11	)/MMBtu
Electricity	$	95	$	(122	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(3	)	—	$	16	/MWh	$	4	/MWh

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

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

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2014 and December 31, 2013:

	June 30, 2014								December 31, 2013
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	46	$	—	$	—	$	46	$	41	$	—	$	—	$	41
Dividends payable	$	238	$	238	$	—	$	—	$	116	$	116	$	—	$	—
Short-term borrowings	$	511	$	—	$	511	$	—	$	131	$	—	$	131	$	—
Long-term debt, excluding capital leases	$	8,030	$	483	$	7,511	$	801	$	8,094	$	425	$	7,551	$	499

See Note 5 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, 2014		December 31, 2013
	(In millions)
Fermi 2	$	1,214	$	1,172
Fermi 1	3		3
Low level radioactive waste	20		16
Total	$	1,237	$	1,191

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In millions)
Realized gains	$	7		$	11		$	16		$	19
Realized losses	$	(4	)	$	(7	)	$	(11	)	$	(14	)
Proceeds from sales of securities	$	204		$	173		$	475		$	309

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, 2014				December 31, 2013
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	762	$	220	$	730	$	201
Debt securities	462		19		442		12
Cash and cash equivalents	13		—		19		—
	$	1,237	$	239	$	1,191	$	213

The debt securities at June 30, 2014 and December 31, 2013 had an average maturity of approximately 7 years, respectively. Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As DTE Electric does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be other-than-temporary impairments.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. DTE Electric recognized $28 million and $31 million of unrealized losses as Regulatory assets at June 30, 2014 and December 31, 2013, 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, 2014 and 2013 for Fermi 1.

Other Securities

At June 30, 2014 and December 31, 2013, the securities were comprised primarily of money market and equity securities. During the three and six months ended June 30, 2014 and 2013, no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income and realized into net income for the periods. Gains related to trading securities held at June 30, 2014 and 2013 were $8 million and $9 million, respectively.

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Accounting Pronouncements (Notes)

6 Months Ended

Jun. 30, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

NEW ACCOUNTING PRONOUNCEMENTS

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

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2014

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

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

Comprehensive Income [Policy Text Block]

Comprehensive Income (Loss)

Comprehensive income (loss) is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following tables, amounts recorded to accumulated other comprehensive loss for the three and six months ended June 30, 2014 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 [Policy Text Block]

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

Fair Value Measurement, Policy [Policy Text Block]

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at June 30, 2014 and December 31, 2013. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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

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

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

Nuclear Decommissioning Trust and Other Investments, Policy [Policy Text Block]

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

Derivatives, Reporting of Derivative Activity [Policy Text Block]

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

Fair Value Transfer, Policy [Policy Text Block]

Derivatives are transferred between levels primarily due to changes in the source data used to construct price curves as a result of changes in market liquidity. Transfers in and transfers out are reflected as if they had occurred at the beginning of the period.

Fair Value of Financial Instruments, Policy [Policy Text Block]

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

Derivatives, Policy [Policy Text Block]

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

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

Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block]

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

The Company also provides and receives collateral in the form of letters of credit which can be offset against net derivative assets and liabilities as well as accounts receivable and payable. The Company had issued letters of credit of approximately $18 million and $19 million at June 30, 2014 and December 31, 2013, respectively, which could be used to offset net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were not material for the periods presented. Such balances of letters of credit are excluded from the tables below and are not netted with the recognized assets and liabilities in the Consolidated Statements of Financial Position.

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

Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]

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

Income Tax, Policy [Policy Text Block]

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

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Commitments and Contingencies (Notes)

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Environmental

Electric

Air - DTE Electric is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. 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 $2 billion through 2013. The Company estimates DTE Electric will make capital expenditures of approximately $280 million in 2014 and up to approximately $1.2 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and other hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, 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 (Court of Appeals) 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 of Appeals issued its decision, vacating CSAPR and leaving CAIR in place. The EPA's petition seeking a rehearing of the 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 for a review of the Court of Appeals' decision on CSAPR. On April 29, 2014, the U.S. Supreme Court issued its ruling reversing the Court of Appeals' stay decision and remanding the case for further proceedings. The EPA has since requested the Court of Appeals to lift the stay on CSAPR and proposed that phase one of the rule would start effective January 2015. Notwithstanding the U.S. Supreme Court remand decision and potential decision by the Court of Appeals to lift the stay, DTE Electric expects to meet its obligations under CSAPR beginning in 2015. Furthermore, the EPA and a number of states, including Michigan, have started working on the framework of revised CSAPR regulations which may still be proposed in the next few years to address other challenges to the existing CSAPR regulations. DTE Electric will continue to monitor these developments and adjust its compliance strategy accordingly.

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

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

In August 2010, the U.S. Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and DTE Electric, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require DTE Electric to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require DTE Electric to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from DTE Electric's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and DTE Electric. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. On March 28, 2013, the Court of Appeals remanded the case to the U.S. District Court for review of the procedural component of the New Source Review notification requirements. On September 3, 2013, the EPA caused to be filed a motion seeking leave to amend their complaint regarding the June 2010 NOV/FOV adding additional claims related to outage work performed at the Trenton Channel and Belle River power plants as well as additional claims related to work performed at the Monroe Power Plant. In addition, the Sierra Club caused to be filed a motion to add a claim regarding the River Rouge Power Plant. On March 3, 2014, the U.S. District Court judge granted again DTE Energy's motion for summary judgment dismissing the civil case related to Monroe Unit 2. On April 3, 2014, the U.S. District Court judge granted motions filed by the EPA and the Sierra Club to amend their New Source Review complaint adding additional claims for Monroe Units 1, 2 and 3, Belle River Units 1 and 2, Trenton Channel Unit 9 and River Rouge Unit 3. On June 30, 2014, the EPA filed a motion requesting certification for appeal of the March 3, 2014 summary judgment decision.

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

In March 2013, the Sierra Club filed suit against DTE Energy and DTE Electric alleging violations of the Clean Air Act at four of DTE Electric's coal-fired power plants. The plaintiffs allege 1,499six-minute periods of excess opacity of air emissions from 2007-2012 at those facilities. The suit asks that the court enjoin DTE Energy and DTE Electric from operating the power plants except in complete compliance with applicable laws and permit requirements, pay civil penalties, conduct beneficial environmental mitigation projects, pay attorney fees and require the installation of any necessary pollution controls or to convert and/or operate the plants' boilers on natural gas to avoid additional violations and to off-set historic unlawful emissions. In December 2013, a U.S. District Court judge issued an order dismissing, without prejudice, the plaintiff's complaint allowing them to file an amended complaint by January 17, 2014. The order dismissing the complaint resulted from a considerable number of plaintiff's claims being time barred based on the statute of limitations. On January 17, 2014, the plaintiffs filed an amended complaint for the period January 13, 2008 - June 30, 2012, reducing the total number of six-minute periods from 1,499 to 1,139. DTE Energy and DTE Electric filed an answer to the amended complaint on March 11, 2014. The resolution of this matter is not expected to have a material effect on the Company's operations or financial statements.

Water — In response to an EPA regulation, DTE Electric would be required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, DTE Electric may be required to install technologies to reduce the impacts of the water intake structures. The initial rule published in 2004 was subsequently remanded and a proposed rule published in 2011. The final rule was issued on May 19, 2014. The final rule specifies a time period exceeding three years to complete studies to determine the type of technology needed to reduce impacts to fish. Final compliance for the installation of the required technology will be determined by each state on a case by case basis. We are currently evaluating the compliance options and working with the State of Michigan on evaluating whether any controls are needed. These evaluations/studies may require modifications to some existing intake structures. It is not possible to quantify the impact of this rulemaking at this time.

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 September 2015. DTE Electric has provided comments to the EPA. However, it is not possible at this time to quantify the impacts of these developing requirements.

Contaminated and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. DTE Electric conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each MGP site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, electric generating power plants, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At June 30, 2014 and December 31, 2013, the Company had $8 million accrued for remediation, respectively. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company believes the likelihood of a material change to the accrued amount is remote based on current knowledge of the conditions at each site.

DTE Electric owns and operates three permitted engineered ash storage facilities to dispose of fly ash from the coal fired power plants. The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published in June 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. The rules are expected to be finalized by December 2014. It is not possible to quantify the impact of those expected rulemakings at this time.

Gas

Contaminated and Other Sites — Gas segment owns or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. Cleanup of two of the MGP sites is complete and the sites are closed. Partial or complete closure of four additional sites is being pursued in 2014. Cleanup activities associated with the remaining sites will be continued over the next several years. The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. As of June 30, 2014 and December 31, 2013, the Company had $24 million and $28 million accrued for remediation, respectively. Any change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for DTE Gas, which allows DTE Gas to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-utility

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

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

The Company received two NOVs from the Pennsylvania Department of Environmental Protection (PADEP) in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue. The Company recently received a permit to upgrade its existing waste water treatment system and is currently seeking a permit from the PADEP to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend $4 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company will also spend up to an additional $15 million over the next few years to upgrade the treatment technology to biological treatment to meet future regulatory requirements and gain other operational improvement savings.

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

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

Other

In December 2012, 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). Capital costs for pollution controls and/or boiler conversions and the expenses for the one-time energy assessments are not expected to be material.

In 2010, the EPA finalized a new 1-hour sulfur dioxide ambient air quality standard that requires states to submit plans for non-attainment areas to be in compliance by 2017. Michigan's non-attainment area includes DTE Energy facilities in southwest Detroit and areas of Wayne County. Preliminary modeling runs by the MDEQ suggest that emission reductions may be required by significant sources of sulfur dioxide emissions in these areas, including DTE Electric power plants and our Michigan coke battery. The state implementation plan process is in the information gathering stage, and DTE Energy is unable to estimate any required emissions reductions at this time.

Nuclear Operations

Property Insurance

DTE Electric maintains property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. 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 $1.5 billion in primary coverage and $1.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion, subject to a $1 million deductible. The total limit for property damage for non-nuclear events is $2 billion and an aggregate of $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 $35 million per event if the loss associated with any one event at any nuclear plant should exceed the accumulated funds available to NEIL.

Public Liability Insurance

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

Nuclear Fuel Disposal Costs

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

DTE Electric is a party in the litigation against the DOE for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. In July 2012, DTE Electric executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement agreement, including extensions, provides for a claims process and payment of delay-related costs experienced by DTE Electric through 2016. DTE Electric has begun the claims process and claims are being settled and paid on a timely basis. The settlement proceeds reduce the cost of the dry cask storage facility assets and provide reimbursement for related operating expenses. The federal government continues to maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by DTE Electric ratepayers to the federal waste fund await future governmental action.

In February 2013, the U.S. Court of Appeals for the District of Columbia (COA) granted a motion to reopen the fee adequacy litigation to review the DOE's latest fee adequacy report which was released in January 2013. In November 2013, the COA issued a decision ordering the DOE to submit a proposal to Congress to reduce the nuclear waste fee to zero until the DOE enacts an alternative nuclear waste management plan. In January 2014, the DOE submitted such a proposal to Congress that was scheduled to take effect in 90 legislative calendar days, absent legislative action to the contrary. Simultaneously, the DOE filed a petition for rehearing of the November 2013 decision with the COA. In March 2014, the COA denied DOE's petition for rehearing. The 1 mill per kWh fee was reduced to zero effective May 16, 2014.

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, 2014 is approximately $1.1 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at June 30, 2014 is approximately $129 million. Payment under these guarantees is considered remote.

Other Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. The Company’s guarantees are not individually material with maximum potential payments totaling $60 million at June 30, 2014. Payment under these guarantees is considered remote.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of June 30, 2014, the Company had approximately $46 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

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

Purchase Commitments

As of June 30, 2014, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments, renewable energy contracts and energy trading contracts. The Company estimates that these commitments will be approximately $8.6 billion from 2014 through 2051.

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

Bankruptcies

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

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 5 and 7 for a discussion of contingencies related to derivatives and regulatory matters.

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Regulatory Matters (Notes)

6 Months Ended

Jun. 30, 2014

Public Utilities, General Disclosures [Abstract]

Regulatory Matters

REGULATORY MATTERS

Refundable Revenue Decoupling/ Deferred Gain Amortization

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

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

Transitional Reconciliation Mechanism (TRM)

On July 19, 2013, DTE Electric filed its TRM application proposing a transitional tariff option for certain former PLD customers and a modified line extension provision. The application also proposed a recovery mechanism for the deferred net incremental revenue requirement associated with the transition. The net incremental revenue requirement includes costs to install meters and attach customers; system and customer facility upgrades and repairs; and the difference between DTE Electric's tariff rates and any transitional rates approved in the future. On May 13, 2014, the MPSC approved the TRM as requested and also ordered DTE Electric to include in the TRM the PLD transmission delivery service costs incurred while DTE Electric is temporarily relying upon PLD to operate and maintain PLD's system during the system conversion period. The meter installation phase of the transition was completed in June 2014. On July 1, 2014, former PLD customers became customers of DTE Electric.

PSCR Proceedings

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

2012 PSCR Year — In March 2013, DTE Electric filed the 2012 PSCR reconciliation calculating a net under-recovery of approximately $87 million that includes an under-recovery of approximately $148 million for the 2011 PSCR year. The reconciliation includes purchased power costs related to the manual shutdown of our Fermi 2 nuclear power plant in June 2012 caused by the failure of one of the plant's two non-safety related feed-water pumps. The plant was restarted on July 30, 2012, which restored production to nominal 68% of full capacity. In September 2013, the repair to the plant was completed and production was returned to full capacity. DTE Electric was able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. Certain intervenors in the reconciliation case have challenged the recovery of up to $32 million of the Fermi-related purchased power costs. Resolution of this matter is expected by late 2014 or early 2015.

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Long-Term Debt (Debt Redemptions) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	1 Months Ended	6 Months Ended	1 Months Ended
	Jun. 30, 2014	May 31, 2014 DTE Energy [Member] Senior Notes [Member]	Jun. 30, 2014 DTE Energy [Member] Long Term Debt, Other [Member]	Mar. 31, 2014 Electric [Member] Mortgages [Member]	Mar. 31, 2014 Electric [Member] Securitization Bonds [Member]	Jun. 30, 2014 Electric [Member] Tax Exempt Revenue Bonds [Member]	Apr. 30, 2014 Electric [Member] Tax Exempt Revenue Bonds [Member]	Jun. 30, 2014 Electric [Member] Tax-Exempt Revenue Bonds 1 [Member]	Apr. 30, 2014 Electric [Member] Tax-Exempt Revenue Bonds 1 [Member]	May 31, 2014 Gas [Member] Mortgages [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.625%			6.62%	4.875%	2.35%	6.00%	4.65%	8.25%
Extinguishment of Debt, Amount	$ 664	$ 300	$ 3	$ 13	$ 100	$ 36	$ 31	$ 69	$ 32	$ 80

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Financial and Other Derivative Instruments (Notes)

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial and other derivative instruments

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

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

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

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

Gas — DTE Gas purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. DTE Gas has fixed-priced contracts for portions of its expected natural gas supply requirements through March 2017. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. DTE Gas may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are generally not derivatives and are therefore accounted for under the accrual method.

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

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

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

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

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

Credit Risk — The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its June 30, 2014 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

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

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

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

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

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

The following tables present the fair value of derivative instruments as of June 30, 2014 and December 31, 2013:

	June 30, 2014					December 31, 2013
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	(1	)	$	—	$	(1	)
Commodity Contracts:
Natural Gas	271		(318		)	396		(503		)
Electricity	593		(606		)	400		(398		)
Other	45		(39		)	37		(34		)
Total derivatives not designated as hedging instruments:	$	909	$	(964	)	$	833	$	(936	)
Total derivatives:
Current	$	778	$	(830	)	$	691	$	(773	)
Noncurrent	131		(134		)	142		(163		)
Total derivatives	$	909	$	(964	)	$	833	$	(936	)

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

The Company also provides and receives collateral in the form of letters of credit which can be offset against net derivative assets and liabilities as well as accounts receivable and payable. The Company had issued letters of credit of approximately $18 million and $19 million at June 30, 2014 and December 31, 2013, respectively, which could be used to offset net derivative liabilities. Letters of credit received from third parties which could be used to offset our net derivative assets were 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, 2014, the total cash collateral posted, net of cash collateral received, was $26 million. As of December 31, 2013, the total cash collateral posted, net of cash collateral received, was $12 million. As of June 30, 2014, derivative assets and derivative liabilities are shown net of cash collateral of $5 million and $7 million, respectively. As of December 31, 2013, derivative assets and derivative liabilities are shown net of cash collateral of $26 million and $17 million, respectively. The Company recorded cash collateral paid of $30 million and cash collateral received of $6 million not related to unrealized derivative positions as of June 30, 2014. The Company recorded cash collateral paid of $34 million and cash collateral received of $13 million not related to unrealized derivative positions as of December 31, 2013. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2014 and December 31, 2013:

	June 30, 2014									December 31, 2013
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	271		$	(259	)	$	12		$	396		$	(382	)	$	14
Electricity	593			(487		)	106			400			(291		)	109
Other	45			(39		)	6			37			(34		)	3
Total derivative assets	$	909		$	(785	)	$	124		$	833		$	(707	)	$	126
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(318	)	$	264		$	(54	)	$	(503	)	$	395		$	(108	)
Electricity	(606		)	484			(122		)	(398		)	269			(129		)
Other	(39		)	39			—			(34		)	34			—
Other derivative liabilities	(1		)	—			(1		)	(1		)	—			(1		)
Total derivative liabilities	$	(964	)	$	787		$	(177	)	$	(936	)	$	698		$	(238	)

The following table presents the netting offsets of derivative assets and liabilities at June 30, 2014 and December 31, 2013:

	June 30, 2014												December 31, 2013
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	778		$	131		$	(830	)	$	(134	)	$	691		$	142		$	(773	)	$	(163	)
Counterparty netting	(675		)	(105		)	675			105			(566		)	(115		)	566			115
Collateral adjustment	(5		)	—			7			—			(26		)	—			12			5
Total derivatives as reported	$	98		$	26		$	(148	)	$	(29	)	$	99		$	27		$	(195	)	$	(43	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013 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		2014			2013			2014			2013
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	3		$	(1	)	$	(1	)	$	(1	)
Commodity Contracts:
Natural Gas	Operating Revenue	155			46			28			36
Natural Gas	Fuel, purchased power and gas	(9		)	(46		)	11			(32		)
Electricity	Operating Revenue	(45		)	10			88			30
Other	Operating Revenue	(3		)	(1		)	(4		)	—
Total		$	101		$	8		$	122		$	33

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 following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2014:

Commodity	Number of Units
Natural Gas (MMBtu)	815,660,484
Electricity (MWh)	19,527,918
Oil (Gallons)	11,592,000
Foreign Currency Exchange ($ CAD)	79,076,508

Various subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to require that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be required to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily natural gas, power and coal) and the provisions and maturities of the underlying transactions. As of June 30, 2014, DTE Energy's contractual obligation to post collateral in the form of cash or letter of credit in the event of a downgrade to below investment grade, under both hard trigger and soft trigger provisions, was approximately $331 million.

As of June 30, 2014, the Company had approximately $1,082 million of derivatives in net liability positions, for which hard triggers exist. Collateral of approximately $18 million has been posted against such liabilities, including cash and letters of credit. Associated derivative net asset positions for which contractual offset exists were approximately $962 million. The net remaining amount of approximately $102 million is derived from the $331 million noted above.

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Asset Retirement Obligations (Notes)

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2014 follows:

	(In millions)
Asset retirement obligations at December 31, 2013	$	1,827
Accretion	56
Liabilities incurred	9
Liabilities settled	(4		)
Revision in estimated cash flows	(5		)
Asset retirement obligations at June 30, 2014	$	1,883

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Earnings Per Share (Notes)

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Earnings per Share

EARNINGS PER SHARE

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014		2013			2014		2013
	(In millions, except per share amounts)
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	124	$	105		$	450	$	339
Average number of common shares outstanding	177		174			177		174
Weighted average net restricted shares outstanding	—		1			—		1
Dividends declared — common shares	$	116	$	114		$	231	$	222
Dividends declared — net restricted shares	—		1			1		—
Total distributed earnings	$	116	$	115		$	232	$	222
Net income less distributed earnings	$	8	$	(10	)	$	218	$	117
Distributed (dividends per common share)	$	0.66	$	0.66		$	1.31	$	1.28
Undistributed	0.04		(0.06		)	1.23		0.66
Total Basic Earnings per Common Share	$	0.70	$	0.60		$	2.54	$	1.94
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	124	$	105		$	450	$	339
Average number of common shares outstanding	177		175			177		174
Weighted average net restricted shares outstanding	—		1			—		1
Dividends declared — common shares	$	116	$	114		$	231	$	222
Dividends declared — net restricted shares	—		1			1		—
Total distributed earnings	$	116	$	115		$	232	$	222
Net income less distributed earnings	$	8	$	(10	)	$	218	$	117
Distributed (dividends per common share)	$	0.66	$	0.66		$	1.31	$	1.28
Undistributed	0.04		(0.06		)	1.23		0.66
Total Diluted Earnings per Common Share	$	0.70	$	0.60		$	2.54	$	1.94

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Commitments and Contingencies (Details Textuals) (USD $)	6 Months Ended		0 Months Ended			3 Months Ended	6 Months Ended		6 Months Ended		6 Months Ended			6 Months Ended
	Jun. 30, 2014 employees	Dec. 31, 2010 dte_instances	May 19, 2014 Electric [Member]	May 16, 2014 Electric [Member] kWh	Dec. 30, 2013 Electric [Member]	Dec. 31, 2013 Electric [Member]	Jun. 30, 2014 Electric [Member] facilities kWh dte_instances	Mar. 31, 2013 Electric [Member] dte_instances	Jun. 30, 2014 Gas [Member] facilities	Dec. 31, 2013 Gas [Member]	Jun. 30, 2014 Synthetic Fuel [Member]	Jun. 30, 2014 Emissions [Member]	Jun. 30, 2014 Other Guarantees [Member]	Jun. 30, 2014 Cleanup completed and site closed [Member] Gas [Member] facilities	Jun. 30, 2014 Partial or complete closure being pursued [Member] Gas [Member] facilities
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Prior Year End							$ 2,000,000,000
Environmental Capital Expenditures in Current Year							280,000,000
Environmental Capital Expenditures In Future Years							1,200,000,000
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							1,139	1,499
Time period to complete studies on cooling water intake structures impacts on fish - EPA ruling			3 years
Period of excess opacity of air emissions at alleged facilities							6 minutes
Number of Former MGP Sites							3		15					2	4
Accrual for Environmental Loss Contingencies, Gross						8,000,000	8,000,000		24,000,000	28,000,000
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	4,000,000
Estimated maximum spend to upgrade treatment technology to biological treatment to meet future requirements	15,000,000
Length of Notice of Intent to sue from the Group Against Smog and Pollution	60 days
Fine related to consent order and agreement with Allegheny County related to NOV	300,000
Estimated expenditures for a supplemental environmental project to enhance particulate collection efficiency	300,000
EPA Sulfur Dioxide Ambient Air Quality Standard	1 hour
Waiting Period of Policy	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							1,500,000,000
Coverage for Stabilization Decontamination Debris Removal Repair and Replacement of Property and Decommissioning							1,250,000,000
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							2,000,000,000
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							35,000,000
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							127,300,000
Limit Deferred Premium Charges Per Year							19,000,000
Company Obligated to Pay DOE Fee of Fermi 2 Electricity Generated and Sold							1
New DOE fee for nuclear waste				0
Court of Appeals proposal to congress to reduce nuclear waste fee, amount						0
Time period after which the Court of Appeals proposal to Congress for nuclear waste fee reduction will take effect duration					90 days
Days Obligations will Survive After Expiration of All Applicable Statutes of Limiations											90 days	90 days
Guarantor Obligations, Maximum Exposure, Undiscounted											1,100,000,000	129,000,000	60,000,000
Performance Bonds Outstanding	46,000,000
Number of Represented Employees	4,900
Long-term Purchase Commitment, Amount	8,600,000,000
Purchase Obligation, Future Minimum Payments, Remainder of Fiscal Year	$ 2,300,000,000

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Retirement Benefits and Trusteed Assets (Details Textuals) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year	$ 145
Qualified Plans [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Contributions by Employer	101
Estimated Future Employer Contributions in Current Fiscal Year	$ 90

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Short-Term Credit Arrangements and Borrowings (Details Textuals) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Revolving Credit Facilities with a Syndicate Number of Banks	19
Number of Banks that Provide Percentage of Commitment in any Facility	1
Maximum Percentage of Commitment to Bank in any Facility	8.70%
Maximum Total Funded Debt to Total Capitalization Ratio	0.65
Other outstanding letters of credit	$ 719
DTE Energy [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio, Amount	0.49
Other outstanding letters of credit	444
Electric [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio, Amount	0.52
Other outstanding letters of credit	275
Gas [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio, Amount	0.44
Other outstanding letters of credit	0
Letter of Credit [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	208
Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	208
Letter of Credit [Member] | Electric [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	0
Letter of Credit [Member] | Gas [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	0
Demand Financing Agreement with Newedge plus letter of credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Financing Agreement, Maximum Borrowing Capacity	150
Demand Financing Agreement with Newedge [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Financing Agreement, Maximum Borrowing Capacity	100
Maximum Additional Margin Financing	50
Financing Agreement, Amount Outstanding	47	138
Other outstanding letters of credit [Member] | Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Other outstanding letters of credit	36
Demand Financing Agreement with Newedge letter of credit to raise capacity [Member] | Letter of Credit [Member] | DTE Energy [Member]
Short-term Debt [Line Items]
Financing Agreement, Maximum Borrowing Capacity	$ 50

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2014

Segment Reporting [Abstract]

Reconciliation of Revenue from Segments to Consolidated [Table Text Block]

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014		2013
	(In millions)
Inter-segment Revenues
Electric	$	7		$	7		$	14	$	13
Gas	2			1			4		2
Gas Storage and Pipelines	7			2			8		4
Power and Industrial Projects	176			185			382		390
Energy Trading	7			12			16		23
Corporate and Other	(1		)	(7		)	1		(15		)
	$	198		$	200		$	425	$	417

Financial data of the business segments follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In millions)
Operating Revenues
Electric	$	1,279		$	1,265		$	2,691		$	2,484
Gas	229			248			1,033			852
Gas Storage and Pipelines	45			31			97			58
Power and Industrial Projects	523			429			1,098			919
Energy Trading	819			451			2,133			844
Corporate & Other	1			1			1			1
Reconciliation & Eliminations	(198		)	(200		)	(425		)	(417		)
Total	$	2,698		$	2,225		$	6,628		$	4,741

Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block]

Net Income (Loss) Attributable to DTE Energy by Segment:
Electric	$	129		$	89		$	265		$	204
Gas	(4		)	8			125			104
Gas Storage and Pipelines	18			16			39			33
Power and Industrial Projects	13			7			28			19
Energy Trading	(14		)	(2		)	28			5
Corporate & Other	(18		)	(13		)	(35		)	(26		)
Net Income Attributable to DTE Energy	$	124		$	105		$	450		$	339

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Financial and Other Derivative Instruments Financial and Other Derivative Instruments (Netting Offsets of Derivative Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 909	$ 833
Gross Amounts Offset in the Statements of Financial Position	(785)	(707)
Net Amounts of Assets Presented in the Statements of Financial Position	124	126
Fair Value Gross Amounts of Recognized (Liabilities)	(964)	(936)
Gross Amounts Offset in the Statement of Financial Position	787	698
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	(177)	(238)
Natural Gas Commodity Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	271	396
Gross Amounts Offset in the Statements of Financial Position	(259)	(382)
Net Amounts of Assets Presented in the Statements of Financial Position	12	14
Fair Value Gross Amounts of Recognized (Liabilities)	(318)	(503)
Gross Amounts Offset in the Statement of Financial Position	264	395
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	(54)	(108)
Electricity Commodity Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	593	400
Gross Amounts Offset in the Statements of Financial Position	(487)	(291)
Net Amounts of Assets Presented in the Statements of Financial Position	106	109
Fair Value Gross Amounts of Recognized (Liabilities)	(606)	(398)
Gross Amounts Offset in the Statement of Financial Position	484	269
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	(122)	(129)
Other Commodity Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Derivative Asset, Fair Value, Gross Asset	45	37
Gross Amounts Offset in the Statements of Financial Position	(39)	(34)
Net Amounts of Assets Presented in the Statements of Financial Position	6	3
Fair Value Gross Amounts of Recognized (Liabilities)	(39)	(34)
Gross Amounts Offset in the Statement of Financial Position	39	34
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	0	0
Other Derivative Contract [Member]
Netting Offsets of Derivative Assets and Liabilities [Line Items]
Fair Value Gross Amounts of Recognized (Liabilities)	(1)	(1)
Gross Amounts Offset in the Statement of Financial Position	0	0
Net Amounts of (Liabilities) Presented in the Statements of Financial Position	$ (1)	$ (1)

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Stock-Based Compensation (Notes)

6 Months Ended

Jun. 30, 2014

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,
	2014		2013		2014		2013
	(In millions)
Stock-based compensation expense	$	16	$	35	$	50	$	63
Tax benefit	$	6	$	14	$	19	$	25
Stock-based compensation cost capitalized in property, plant and equipment	$	2	$	2	$	7	$	4

Stock Options

The following table summarizes our stock option activity for the six months ended June 30, 2014:

	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value (In millions)
Options outstanding at January 1, 2014	723,697		$	42.60
Exercised	(204,108	)	$	41.54
Forfeited or expired	(10,730	)	$	39.41
Options outstanding and exercisable at June 30, 2014	508,859		$	43.10	$	17

As of June 30, 2014, the weighted average remaining contractual life for the exercisable shares is 3.74 years. As of June 30, 2014, all options were vested.

The intrinsic value of options exercised for the six months ended June 30, 2014 and 2013 was $6 million and $10 million, respectively. No option expense was recognized for the six months ended June 30, 2014 and 2013, respectively.

Restricted Stock Awards

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2014:

	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2014	492,329		$	53.76
Grants	156,390		$	69.95
Forfeitures	(13,764	)	$	62.25
Vested and issued	(216,103	)	$	47.58
Balance at June 30, 2014	418,852		$	62.71

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. Awards granted in 2014 were primarily deemed to be equity awards. The stock price and number of probable shares attributable to market conditions for such equity awards are fair valued only at the grant date. Performance shares awarded prior to 2014 are liability awards and are remeasured to fair value at each reporting period.

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2014:

	Performance Shares		Weighted Average Grant Date Fair Value
Balance at January 1, 2014	1,608,789		$	—
Grants	532,585		$	69.16
Forfeitures	(27,390	)	$	69.10
Payouts	(571,177	)	$	—
Balance at June 30, 2014	1,542,807		$	69.17

Unrecognized Compensation Costs

As of June 30 2014, there was $82 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 1.48 years.

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Fair Value (Tables)

6 Months Ended

Jun. 30, 2014

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, 2014 and December 31, 2013:

	June 30, 2014															December 31, 2013
	Level 1			Level 2			Level 3			Netting (a)			Net Balance			Level 1			Level 2			Level 3			Netting (a)			Net Balance
	(In millions)
Assets:
Cash equivalents (b)	$	12		$	96		$	—		$	—		$	108		$	10		$	115		$	—		$	—		$	125
Nuclear decommissioning trusts	798			439			—			—			1,237			779			412			—			—			1,191
Other investments (c) (d)	94			50			—			—			144			92			44			—			—			136
Derivative assets:
Commodity Contracts:
Natural Gas	118			101			52			(259		)	12			273			89			34			(382		)	14
Electricity	—			498			95			(487		)	106			—			261			139			(291		)	109
Other	35			3			7			(39		)	6			33			1			3			(34		)	3
Total derivative assets	153			602			154			(785		)	124			306			351			176			(707		)	126
Total	$	1,057		$	1,187		$	154		$	(785	)	$	1,613		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(123	)	$	(123	)	$	(72	)	$	264		$	(54	)	$	(277	)	$	(140	)	$	(86	)	$	395		$	(108	)
Electricity	—			(484		)	(122		)	484			(122		)	—			(272		)	(126		)	269			(129		)
Other	(32		)	(7		)	—			39			—			(32		)	(2		)	—			34			—
Other derivative contracts (f)	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Total derivative liabilities	(155		)	(615		)	(194		)	787			(177		)	(309		)	(415		)	(212		)	698			(238		)
Total	$	(155	)	$	(615	)	$	(194	)	$	787		$	(177	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	902		$	572		$	(40	)	$	2		$	1,436		$	878		$	507		$	(36	)	$	(9	)	$	1,340
Assets:
Current	$	145		$	618		$	123		$	(680	)	$	206		$	277		$	400		$	139		$	(592	)	$	224
Noncurrent (e)	912			569			31			(105		)	1,407			910			522			37			(115		)	1,354
Total Assets	$	1,057		$	1,187		$	154		$	(785	)	$	1,613		$	1,187		$	922		$	176		$	(707	)	$	1,578
Liabilities:
Current	$	(133	)	$	(528	)	$	(169	)	$	682		$	(148	)	$	(268	)	$	(328	)	$	(177	)	$	578		$	(195	)
Noncurrent	(22		)	(87		)	(25		)	105			(29		)	(41		)	(87		)	(35		)	120			(43		)
Total Liabilities	$	(155	)	$	(615	)	$	(194	)	$	787		$	(177	)	$	(309	)	$	(415	)	$	(212	)	$	698		$	(238	)
Net Assets (Liabilities) at the end of the period	$	902		$	572		$	(40	)	$	2		$	1,436		$	878		$	507		$	(36	)	$	(9	)	$	1,340

_______________________________________

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

(b) At June 30, 2014, available-for-sale securities of $108 million included $95 million and $13 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. At December 31, 2013, available-for-sale securities of $125 million, included $109 million and $16 million of cash equivalents included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.

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

(d) Available-for-sale equity securities of $7 million at both June 30, 2014 and December 31, 2013, are included in Other investments on the Consolidated Statements of Financial Position.

(e) Includes $144 million and $136 million at June 30, 2014 and December 31, 2013, respectively, of other investments that are included in the Consolidated Statements of Financial Position in Other investments.

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

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30, 2014												Three Months Ended June 30, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of April 1	$	(10	)	$	(34	)	$	1		$	(43	)	$	(34	)	$	(9	)	$	2		$	(41	)
Transfers into Level 3	—			—			—			—			—			—			—			—
Transfers out of Level 3	—			—			—			—			—			—			—			—
Total gains (losses):
Included in earnings	(16		)	(22		)	(1		)	(39		)	(2		)	18			(1		)	15
Recorded in regulatory assets/liabilities	—			—			7			7			—			—			3			3
Purchases, issuances and settlements:
Issuances	—			(1		)	—			(1		)	—			—			—			—
Settlements	6			30			—			36			6			3			(2		)	7
Net Assets (Liabilities) as of June 30	$	(20	)	$	(27	)	$	7		$	(40	)	$	(30	)	$	12		$	2		$	(16	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(11	)	$	1		$	—		$	(10	)	$	(1	)	$	33		$	(1	)	$	31

	Six Months Ended June 30, 2014												Six Months Ended June 30, 2013
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
	(In millions)
Net Assets (Liabilities) as of January 1	$	(52	)	$	13		$	3		$	(36	)	$	(38	)	$	23		$	2		$	(13	)
Transfers into Level 3	—			—			—			—			—			—			—			—
Transfers out of Level 3	—			—			—			—			(2		)	—			—			(2		)
Total gains (losses):
Included in earnings	(38		)	20			(1		)	(19		)	(10		)	26			(1		)	15
Recorded in regulatory assets/liabilities	—			—			11			11			—			—			4			4
Purchases, issuances and settlements:
Purchases	—			—			—			—			—			1			—			1
Issuances	—			(2		)	—			(2		)	—			—			—			—
Settlements	70			(58		)	(6		)	6			20			(38		)	(3		)	(21		)
Net Assets (Liabilities) as of June 30	$	(20	)	$	(27	)	$	7		$	(40	)	$	(30	)	$	12		$	2		$	(16	)
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, 2014 and 2013 and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(11	)	$	(19	)	$	—		$	(30	)	$	(6	)	$	27		$	(1	)	$	20

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 and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30, 2014					Three Months Ended June 30, 2013
	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		—	—		N/A

	Six Months Ended June 30, 2014					Six Months Ended June 30, 2013
	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		2
Transfers into Level 3 from	—	—		N/A		—	—		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, 2014:

	June 30, 2014
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range							Weighted Average
	(In millions)
Natural Gas	$	52	$	(72	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.80	)	—	$	6.98	/MMBtu	$	(0.11	)/MMBtu
Electricity	$	95	$	(122	)	Discounted Cash Flow	Forward basis price (per MWh)	$	(3	)	—	$	16	/MWh	$	4	/MWh

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

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

Fair Value of Financial Instruments [Table Text Block]

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2014 and December 31, 2013:

	June 30, 2014								December 31, 2013
	Carrying		Fair Value						Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Amount		Level 1		Level 2		Level 3
	(In millions)
Notes receivable, excluding capital leases	$	46	$	—	$	—	$	46	$	41	$	—	$	—	$	41
Dividends payable	$	238	$	238	$	—	$	—	$	116	$	116	$	—	$	—
Short-term borrowings	$	511	$	—	$	511	$	—	$	131	$	—	$	131	$	—
Long-term debt, excluding capital leases	$	8,030	$	483	$	7,511	$	801	$	8,094	$	425	$	7,551	$	499

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

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

	June 30, 2014		December 31, 2013
	(In millions)
Fermi 2	$	1,214	$	1,172
Fermi 1	3		3
Low level radioactive waste	20		16
Total	$	1,237	$	1,191

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,
	2014			2013			2014			2013
	(In millions)
Realized gains	$	7		$	11		$	16		$	19
Realized losses	$	(4	)	$	(7	)	$	(11	)	$	(14	)
Proceeds from sales of securities	$	204		$	173		$	475		$	309

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

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

	June 30, 2014				December 31, 2013
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
	(In millions)
Equity securities	$	762	$	220	$	730	$	201
Debt securities	462		19		442		12
Cash and cash equivalents	13		—		19		—
	$	1,237	$	239	$	1,191	$	213

XML

Fair Value (Details Textuals) (USD $)	3 Months Ended	6 Months Ended		3 Months Ended		6 Months Ended				3 Months Ended		6 Months Ended			12 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014 Accumulated Net Unrealized Investment Gain (Loss) [Member]	Jun. 30, 2013 Accumulated Net Unrealized Investment Gain (Loss) [Member]	Jun. 30, 2014 Accumulated Net Unrealized Investment Gain (Loss) [Member]	Jun. 30, 2013 Accumulated Net Unrealized Investment Gain (Loss) [Member]	Jun. 30, 2014 Fermi 2 [Member]	Dec. 31, 2013 Fermi 2 [Member]	Jun. 30, 2014 Fermi 1 [Member]	Jun. 30, 2013 Fermi 1 [Member]	Jun. 30, 2014 Fermi 1 [Member]	Jun. 30, 2013 Fermi 1 [Member]	Jun. 30, 2014 Nuclear Decommissioning Trust Fund [Member]	Dec. 31, 2013 Nuclear Decommissioning Trust Fund [Member]	Jun. 30, 2014 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member]	Jun. 30, 2014 Restricted Assets [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Restricted Assets [Member] Fair Value, Measurements, Recurring [Member]	Jun. 30, 2014 Other Investments [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Other Investments [Member] Fair Value, Measurements, Recurring [Member]	Jun. 30, 2014 Other Investments [Member] Fair Value, Measurements, Recurring [Member] Equity [Member]	Dec. 31, 2013 Other Investments [Member] Fair Value, Measurements, Recurring [Member] Equity [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure														$ 13,000,000	$ 19,000,000	$ 108,000,000	$ 125,000,000	$ 95,000,000	$ 109,000,000	$ 13,000,000	$ 16,000,000
Available-for-sale Securities, Fair Value Disclosure																						7,000,000	7,000,000
Other investments																						144,000,000	136,000,000
Average Maturity of Debt Securities														7 years	7 years
Unrealized losses recognized as regulatory assets								28,000,000	31,000,000
Unrealized losses recognized in earnings										0	0	0	0
Unrealized on Available for Sale Securities	(1,000,000)	(3,000,000)		0	0	0	0
Trading Securities, Realized Gain (Loss)		$ 8,000,000	$ 9,000,000

XML

Fair Value (Assets and Liabilities Recorded at Fair Value on a Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Assets [Abstract]
Nuclear decommissioning trusts	$ 1,237	$ 1,191
Liabilities [Abstract]
Derivative Liabilities, Current	(148)	(195)
Derivative Liabilities, Noncurrent	(29)	(43)
Fair Value, Measurements, Recurring [Member]
Assets [Abstract]
Cash and Cash Equivalents	108	125
Nuclear decommissioning trusts	1,237	1,191
Other Investments	144	136
Derivative assets [Abstract]
Derivative Assets	124	126
Assets, Fair Value Disclosure	1,613	1,578
Liabilities [Abstract]
Derivative Liabilities	(177)	(238)
Fair Value, Net Asset (Liability)	1,436	1,340
Derivative Liabilities, Current	(148)	(195)
Derivative Liabilities, Noncurrent	(29)	(43)
Fair Value, Measurements, Recurring [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	12	14
Liabilities [Abstract]
Derivative Liabilities	(54)	(108)
Fair Value, Measurements, Recurring [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	106	109
Liabilities [Abstract]
Derivative Liabilities	(122)	(129)
Fair Value, Measurements, Recurring [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	6	3
Liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Other Derivative Contract [Member]
Liabilities [Abstract]
Derivative Liabilities	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Cash and Cash Equivalents	12	10
Nuclear decommissioning trusts	798	779
Other Investments	94	92
Derivative assets [Abstract]
Derivative Assets	153	306
Assets, Fair Value Disclosure	1,057	1,187
Liabilities [Abstract]
Derivative Liabilities	(155)	(309)
Fair Value, Net Asset (Liability)	902	878
Derivative Liabilities, Current	(133)	(268)
Derivative Liabilities, Noncurrent	(22)	(41)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	118	273
Liabilities [Abstract]
Derivative Liabilities	(123)	(277)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	0	0
Liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	35	33
Liabilities [Abstract]
Derivative Liabilities	(32)	(32)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Derivative Contract [Member]
Liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Cash and Cash Equivalents	96	115
Nuclear decommissioning trusts	439	412
Other Investments	50	44
Derivative assets [Abstract]
Derivative Assets	602	351
Assets, Fair Value Disclosure	1,187	922
Liabilities [Abstract]
Derivative Liabilities	(615)	(415)
Fair Value, Net Asset (Liability)	572	507
Derivative Liabilities, Current	(528)	(328)
Derivative Liabilities, Noncurrent	(87)	(87)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	101	89
Liabilities [Abstract]
Derivative Liabilities	(123)	(140)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	498	261
Liabilities [Abstract]
Derivative Liabilities	(484)	(272)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	3	1
Liabilities [Abstract]
Derivative Liabilities	(7)	(2)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Derivative Contract [Member]
Liabilities [Abstract]
Derivative Liabilities	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Cash and Cash Equivalents	0	0
Nuclear decommissioning trusts	0	0
Other Investments	0	0
Derivative assets [Abstract]
Derivative Assets	154	176
Assets, Fair Value Disclosure	154	176
Liabilities [Abstract]
Derivative Liabilities	(194)	(212)
Fair Value, Net Asset (Liability)	(40)	(36)
Derivative Liabilities, Current	(169)	(177)
Derivative Liabilities, Noncurrent	(25)	(35)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	52	34
Liabilities [Abstract]
Derivative Liabilities	(72)	(86)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	95	139
Liabilities [Abstract]
Derivative Liabilities	(122)	(126)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	7	3
Liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Derivative Contract [Member]
Liabilities [Abstract]
Derivative Liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Netting [Member]
Assets [Abstract]
Cash and Cash Equivalents	0	0
Nuclear decommissioning trusts	0	0
Other Investments	0	0
Derivative assets [Abstract]
Derivative Assets	(785)	(707)
Assets, Fair Value Disclosure	(785)	(707)
Liabilities [Abstract]
Derivative Liabilities	787	698
Fair Value, Net Asset (Liability)	(2)	9
Derivative Liabilities, Current	682	578
Derivative Liabilities, Noncurrent	105	120
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Natural Gas Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	(259)	(382)
Liabilities [Abstract]
Derivative Liabilities	264	395
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Electricity Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	(487)	(291)
Liabilities [Abstract]
Derivative Liabilities	484	269
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Other Commodity Contract [Member]
Derivative assets [Abstract]
Derivative Assets	(39)	(34)
Liabilities [Abstract]
Derivative Liabilities	39	34
Fair Value, Measurements, Recurring [Member] | Netting [Member] | Other Derivative Contract [Member]
Liabilities [Abstract]
Derivative Liabilities	0	0
Current Asset [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	206	224
Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	145	277
Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	618	400
Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	123	139
Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Netting [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	(680)	(592)
Non Current Asset [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	1,407	1,354
Non Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	912	910
Non Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	569	522
Non Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	31	37
Non Current Asset [Member] | Fair Value, Measurements, Recurring [Member] | Netting [Member]
Derivative assets [Abstract]
Assets, Fair Value Disclosure	$ (105)	$ (115)

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Consolidated Statements of Financial Position (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current Assets
Cash and cash equivalents	$ 75	$ 52
Restricted cash, principally Securitization	110	123
Accounts receivable (less allowance for doubtful accounts of $60 and $55, respectively)
Customer	1,400	1,542
Other	126	127
Inventories
Fuel and gas	342	363
Materials and supplies	277	265
Derivative assets	98	99
Regulatory assets	127	26
Other	166	209
Total Current Assets	2,721	2,806
Investments
Nuclear decommissioning trust funds	1,237	1,191
Other	604	603
Total Investments	1,841	1,794
Property
Property, plant and equipment	25,836	25,123
Less accumulated depreciation, depletion and amortization	(9,529)	(9,323)
Property, plant and equipment, net	16,307	15,800
Other Assets
Goodwill	2,018	2,018
Regulatory assets	2,719	2,837
Securitized regulatory assets	135	231
Intangible assets	112	122
Notes receivable	90	102
Derivative assets	26	27
Other	220	198
Total Noncurrent Assets	5,320	5,535
Total Assets	26,189	25,935
Current Liabilities
Accounts payable	946	962
Accrued interest	86	90
Dividends payable	238	116
Short-term borrowings	511	131
Current portion long-term debt, including capital leases	229	898
Derivative liabilities	148	195
Gas inventory equalization	38	0
Regulatory liabilities	150	302
Other	473	495
Total Current Liabilities	2,819	3,189
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	7,329	6,618
Securitization bonds	0	105
Junior subordinated debentures	480	480
Capital lease obligations	4	11
Total Long-Term Debt (net of current portion)	7,813	7,214
Other Liabilities
Deferred income taxes	3,500	3,321
Regulatory liabilities	757	862
Asset retirement obligations	1,883	1,827
Unamortized investment tax credit	42	47
Derivative liabilities	29	43
Accrued pension liability	564	653
Accrued postretirement liability	307	350
Nuclear decommissioning	180	178
Other	269	297
Total Noncurrent Liabilities	7,531	7,578
Commitments and Contingencies (Notes 7 and 11)
Equity
Common stock, without par value, 400,000,000 shares authorized, 176,993,343 and 177,087,230 shares issued and outstanding, respectively	3,896	3,907
Retained earnings	4,246	4,150
Accumulated other comprehensive loss	(134)	(136)
Total DTE Energy Company Equity	8,008	7,921
Noncontrolling interests	18	33
Total Equity	8,026	7,954
Total Liabilities and Equity	$ 26,189	$ 25,935

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Significant Accounting Policies (Notes)

6 Months Ended

Jun. 30, 2014

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

SIGNIFICANT ACCOUNTING POLICIES

Other Income

Other income is recognized for non-operating income such as equity earnings, interest and dividends, allowance for funds used during construction and contract services. Power & Industrial Projects also recognizes Other income in connection with the sale of membership interests in reduced emissions fuel facilities to investors. In exchange for the cash received, the investors will receive a portion of the economic attributes of the facilities, including income tax attributes. The transactions are not treated as a sale of membership interests for financial reporting purposes. Other income is considered earned when refined coal is produced and tax credits are generated. Power & Industrial Projects recognized approximately $15 million and $20 million of Other income for the three months ended June 30, 2014 and 2013, respectively, and approximately $32 million and $35 million of Other income for the six months ended June 30, 2014 and 2013, respectively.

Comprehensive Income (Loss)

Comprehensive income (loss) is the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following tables, amounts recorded to accumulated other comprehensive loss for the three and six months ended June 30, 2014 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, 2014
	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, 2014	$	(4	)	$	(6	)	$	(126	)	$	(1	)	$	(137	)
Other comprehensive income before reclassifications	—			1			—			1			2
Amounts reclassified from accumulated other comprehensive income	—			—			1			—			1
Net current-period other comprehensive income	—			1			1			1			3
Ending balance, June 30, 2014	$	(4	)	$	(5	)	$	(125	)	$	—		$	(134	)

	Changes in Accumulated Other Comprehensive Loss by Component (a)
	For The Six Months Ended June 30, 2014
	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, 2013	$	(4	)	$	(6	)	$	(126	)	$	—	$	(136	)
Other comprehensive income before reclassifications	—			1			(2		)	—		(1		)
Amounts reclassified from accumulated other comprehensive income	—			—			3			—		3
Net current-period other comprehensive income	—			1			1			—		2
Ending balance, June 30, 2014	$	(4	)	$	(5	)	$	(125	)	$	—	$	(134	)

______________________________________

(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 and other postretirement benefits cost (see Note 12).

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,
	2014		2013
	(In millions)
Emission allowances	$	2	$	2
Renewable energy credits	51		51
Contract intangible assets	123		126
	176		179
Less accumulated amortization	51		45
Intangible assets, net	125		134
Less current intangible assets	13		12
	$	112	$	122

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 1 to 28 years.

Income Taxes

The Company's effective tax rate for the three months ended June 30, 2014 was 28% as compared to 29% for the three months ended June 30, 2013. The Company's effective tax rate for the six months ended June 30, 2014 was 31% as compared to 30% for the six months ended June 30, 2013. The 1% decrease in the effective tax rate for the three months ended June 30, 2014 is due to higher production tax credits. The 1% increase in effective tax rate for the six months ended June 30, 2014 is due to $8 million of deferred tax expense resulting from New York state income tax reform enacted on March 31, 2014, partially offset by higher production tax credits.

The Company had $2 million of unrecognized tax benefits at June 30, 2014, 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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Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 124	$ 105	$ 450	$ 339
Average number of common shares outstanding	177	174	177	174
Weighted average net restricted shares outstanding	0	1	0	1
Dividends declared - common shares	116	114	231	222
Dividends declared - net restricted shares	0	1	1	0
Total distributed earnings	116	115	232	222
Net income less distributed earnings	8	(10)	218	117
Distributed (dividends per common share)	$ 0.66	$ 0.66	$ 1.31	$ 1.28
Undistributed	$ 0.04	$ (0.06)	$ 1.23	$ 0.66
Total Basic Earnings per Common Share	$ 0.70	$ 0.60	$ 2.54	$ 1.94
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	124	105	450	339
Common shares for dilutive calculation	177	175	177	174
Weighted average net restricted shares outstanding	0	1	0	1
Dividends declared - common shares	116	114	231	222
Dividends declared - net restricted shares	0	1	1	0
Total distributed earnings	116	115	232	222
Net income less distributed earnings	$ 8	$ (10)	$ 218	$ 117
Distributed (dividends per common share)	$ 0.66	$ 0.66	$ 1.31	$ 1.28
Undistributed	$ 0.04	$ (0.06)	$ 1.23	$ 0.66
Total Diluted Earnings per Common Share	$ 0.70	$ 0.60	$ 2.54	$ 1.94

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Stock-Based Compensation (Restricted Stock and Performance Share Awards) (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Restricted Stock Awards [Abstract]
Forfeitures	(10,730)
Restricted Stock [Member]
Restricted Stock Awards [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	492,329
Grants	156,390
Forfeitures	(13,764)
Vested and Issued	(216,103)
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number	418,852
Weighted Average Grant Date Fair Value Per Share Balance	$ 53.76
Weighted Average Grant Date Fair Value, Grants	$ 69.95
Weighted Average Grant Date Fair Value, Forfeitures	$ 62.25
Weighted Average Fair Value Per Share, Vested and issued	$ 47.58
Weighted Average Grant Date Fair Value Per Share Balance	$ 62.71
Performance Stock Awards [Abstract]
Weighted Average Grant Date Fair Value Per Share Balance	$ 53.76
Weighted Average Grant Date Fair Value, Grants	$ 69.95
Weighted Average Grant Date Fair Value, Forfeitures	$ 62.25
Weighted Average Grant Date Fair Value Per Share Balance	$ 62.71
Performance Shares [Member]
Restricted Stock Awards [Abstract]
Weighted Average Grant Date Fair Value Per Share Balance	$ 0.00
Weighted Average Grant Date Fair Value, Grants	$ 69.16
Weighted Average Grant Date Fair Value, Forfeitures	$ 69.10
Weighted Average Grant Date Fair Value Per Share Balance	$ 69.17
Performance Stock Awards [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity and Liability Instruments, Outstanding, Number	1,608,789
Grants	532,585
Forfeitures	(27,390)
Payouts	(571,177)
Share-based Compensation Arrangement by Share-based Payment Award, Liability and Equity Instruments Other than Options, Outstanding, Number	1,542,807
Weighted Average Grant Date Fair Value Per Share Balance	$ 0.00
Weighted Average Grant Date Fair Value, Grants	$ 69.16
Weighted Average Grant Date Fair Value, Forfeitures	$ 69.10
Weighted Average Grant Date Fair Value, Payouts	$ 0.00
Weighted Average Grant Date Fair Value Per Share Balance	$ 69.17

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Financial and Other Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivative instruments

The following tables present the fair value of derivative instruments as of June 30, 2014 and December 31, 2013:

	June 30, 2014					December 31, 2013
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
	(In millions)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	—	$	(1	)	$	—	$	(1	)
Commodity Contracts:
Natural Gas	271		(318		)	396		(503		)
Electricity	593		(606		)	400		(398		)
Other	45		(39		)	37		(34		)
Total derivatives not designated as hedging instruments:	$	909	$	(964	)	$	833	$	(936	)
Total derivatives:
Current	$	778	$	(830	)	$	691	$	(773	)
Noncurrent	131		(134		)	142		(163		)
Total derivatives	$	909	$	(964	)	$	833	$	(936	)

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, 2014 and December 31, 2013:

	June 30, 2014									December 31, 2013
	Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position			Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts Offset in the Consolidated Statements of Financial Position			Net Amounts of Assets (Liabilities) Presented in the Consolidated Statements of Financial Position
	(In millions)
Derivative assets:
Commodity Contracts:
Natural Gas	$	271		$	(259	)	$	12		$	396		$	(382	)	$	14
Electricity	593			(487		)	106			400			(291		)	109
Other	45			(39		)	6			37			(34		)	3
Total derivative assets	$	909		$	(785	)	$	124		$	833		$	(707	)	$	126
Derivative liabilities:
Commodity Contracts:
Natural Gas	$	(318	)	$	264		$	(54	)	$	(503	)	$	395		$	(108	)
Electricity	(606		)	484			(122		)	(398		)	269			(129		)
Other	(39		)	39			—			(34		)	34			—
Other derivative liabilities	(1		)	—			(1		)	(1		)	—			(1		)
Total derivative liabilities	$	(964	)	$	787		$	(177	)	$	(936	)	$	698		$	(238	)

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, 2014 and December 31, 2013:

	June 30, 2014												December 31, 2013
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
	(In millions)
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	778		$	131		$	(830	)	$	(134	)	$	691		$	142		$	(773	)	$	(163	)
Counterparty netting	(675		)	(105		)	675			105			(566		)	(115		)	566			115
Collateral adjustment	(5		)	—			7			—			(26		)	—			12			5
Total derivatives as reported	$	98		$	26		$	(148	)	$	(29	)	$	99		$	27		$	(195	)	$	(43	)

Gain (Loss) Recognized in Income on Derivative

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013 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		2014			2013			2014			2013
		(In millions)
Foreign currency exchange contracts	Operating Revenue	$	3		$	(1	)	$	(1	)	$	(1	)
Commodity Contracts:
Natural Gas	Operating Revenue	155			46			28			36
Natural Gas	Fuel, purchased power and gas	(9		)	(46		)	11			(32		)
Electricity	Operating Revenue	(45		)	10			88			30
Other	Operating Revenue	(3		)	(1		)	(4		)	—
Total		$	101		$	8		$	122		$	33

Volume of Commodity Contracts [Table Text Block]

The following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2014:

Commodity	Number of Units
Natural Gas (MMBtu)	815,660,484
Electricity (MWh)	19,527,918
Oil (Gallons)	11,592,000
Foreign Currency Exchange ($ CAD)	79,076,508

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Significant Accounting Policies (Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	$ (137)		$ (136)
Other Comprehensive Income Before Reclassifications	2		(1)
Amounts Reclassified From Accumulated Other Comprehensive Income	1		3
Other Comprehensive Income (Loss), Net of Tax	3	1	2	3
Accumulated Other Comprehensive Income (Loss)	(134)		(134)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(4)		(4)
Other Comprehensive Income Before Reclassifications	0		0
Amounts Reclassified From Accumulated Other Comprehensive Income	0		0
Other Comprehensive Income (Loss), Net of Tax	0		0
Accumulated Other Comprehensive Income (Loss)	(4)		(4)
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(6)		(6)
Other Comprehensive Income Before Reclassifications	1		1
Amounts Reclassified From Accumulated Other Comprehensive Income	0	0	0	0
Other Comprehensive Income (Loss), Net of Tax	1		1
Accumulated Other Comprehensive Income (Loss)	(5)		(5)
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(126)		(126)
Other Comprehensive Income Before Reclassifications	0		(2)
Amounts Reclassified From Accumulated Other Comprehensive Income	1		3
Other Comprehensive Income (Loss), Net of Tax	1		1
Accumulated Other Comprehensive Income (Loss)	(125)		(125)
Accumulated Translation Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(1)		0
Other Comprehensive Income Before Reclassifications	1		0
Amounts Reclassified From Accumulated Other Comprehensive Income	0		0
Other Comprehensive Income (Loss), Net of Tax	1		0
Accumulated Other Comprehensive Income (Loss)	$ 0		$ 0

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Retirement Benefits and Trusteed Assets (Notes)

6 Months Ended

Jun. 30, 2014

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 Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Three Months Ended June 30	(In millions)
Service cost	$	22		$	25		$	9		$	12
Interest cost	52			47			22			21
Expected return on plan assets	(68		)	(66		)	(30		)	(27		)
Amortization of:
Net actuarial loss	38			50			6			15
Prior service credit	—			—			(36		)	(36		)
Net periodic benefit cost (credit)	$	44		$	56		$	(29	)	$	(15	)

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
Six Months Ended June 30	(In millions)
Service cost	$	43		$	49		$	18		$	28
Interest cost	105			95			45			45
Expected return on plan assets	(136		)	(133		)	(61		)	(54		)
Amortization of:
Net actuarial loss	76			101			11			32
Prior service credit	—			—			(72		)	(59		)
Net periodic benefit cost (credit)	$	88		$	112		$	(59	)	$	(8	)

Pension and Other Postretirement Contributions

During the first six months of 2014, the Company contributed $101 million to its pension plans. At the discretion of management, and depending upon financial market conditions, the Company may make up to an additional $90 million contribution to its pension plans in 2014.

At the discretion of management, the Company may make up to a $145 million contribution to its other postretirement benefit plans in 2014.