Edgar Filing: DTE ENERGY CO

e10vq

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, 2011

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.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	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).

Yes o No þ

At June 30, 2011, 169,328,889 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, 2011

TABLE OF CONTENTS


	Page
DEFINITIONS		1
FORWARD-LOOKING STATEMENTS		3
PART I — FINANCIAL INFORMATION
Consolidated Statements of Operations (Unaudited)		5
Consolidated Statements of Financial Position (Unaudited)		6
Consolidated Statements of Cash Flows (Unaudited)		8
Consolidated Statements of Changes in Equity and Comprehensive Income (Unaudited)		9
Notes to Consolidated Financial Statements (Unaudited)		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
Item 3. Quantitative and Qualitative Disclosures About Market Risk		56
Item 4. Controls and Procedures		59
PART II — OTHER INFORMATION
Item 1A. Risk Factors		60
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers		61
Item 6. Exhibits		62
SIGNATURE		63
EX-4.269
EX-31.67
EX-31.68
EX-32.67
EX-32.68
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

DEFINITIONS


ASC		Accounting Standards Codification

ASU		Accounting Standards Update

CIM		A Choice Incentive Mechanism authorized by the MPSC that allows Detroit Edison to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales.

Citizens		Citizens Fuel Gas Company distributes natural gas in Adrian, Michigan

Company		DTE Energy Company and any subsidiary companies

CTA		Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process

Customer Choice		Michigan legislation giving customers the option to choose alternative suppliers for electricity and gas.

Detroit Edison		The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies

DTE Energy		DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries

EPA		United States Environmental Protection Agency

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FTRs		Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.

GCR		A Gas Cost Recovery mechanism authorized by the MPSC that allows MichCon to recover through rates its natural gas costs.

MCIT		Michigan Corporate Income Tax

MDEQ		Michigan Department of Environmental Quality

MichCon		Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies

MISO		Midwest Independent System Operator is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.

MPSC		Michigan Public Service Commission

Non-utility		An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC.

NRC		United States Nuclear Regulatory Commission

Production tax credits		Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.


Proved reserves		Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions.

PSCR		A Power Supply Cost Recovery mechanism authorized by the MPSC that allows Detroit Edison 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 of electricity and natural gas.

Securitization		Detroit Edison 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

Unconventional Gas		Includes those gas and oil deposits that originated and are stored in coal bed, tight sandstone and shale formations

VIE		Variable Interest Entity

Units of Measurement

Bcf		Billion cubic feet of gas

Bcfe		Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil

BTU		Heat value (energy content) of fuel

dth/d		Decatherms per day

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MMcf		Million cubic feet of gas

MW		Megawatt of electricity

MWh		Megawatthour of electricity

Forward-Looking Statements

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

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

	•		changes in the economic and financial viability of suppliers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company;

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

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

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

	•		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;

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

	•		employee relations and the impact of collective bargaining agreements;

	•		unplanned outages;

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

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

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

	•		the effects of competition;

	•		the uncertainties of successful exploration of unconventional gas resources and challenges in estimating gas and oil reserves with certainty;

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

	•		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 amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;

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

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

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

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

	•		binding arbitration, litigation and related appeals; and

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

New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer 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.

Part I — Item 1.

DTE Energy Company
Consolidated Statements of Operations (Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions, Except per Share Amounts)	2011			2010			2011			2010
Operating Revenues	$	2,028		$	1,792		$	4,459		$	4,245


Operating Expenses
Fuel, purchased power and gas		771			608			1,842			1,603
Operation and maintenance		647			597			1,278			1,249
Depreciation, depletion and amortization		248			253			493			504
Taxes other than income		77			80			160			162
Asset (gains) and losses, reserves and impairments, net		(3	)		(2	)		8			(1	)

		1,740			1,536			3,781			3,517


Operating Income		288			256			678			728


Other (Income) and Deductions
Interest expense		124			136			250			276
Interest income		(2	)		(3	)		(5	)		(6	)
Other income		(18	)		(23	)		(39	)		(42	)
Other expenses		8			15			15			23

		112			125			221			251


Income Before Income Taxes		176			131			457			477

Income Tax Provision (Benefit)		(24	)		44			79			160


Net Income		200			87			378			317

Less: Net Income (Loss) Attributable to Noncontrolling Interests		(2	)		1			—			2


Net Income Attributable to DTE Energy Company	$	202		$	86		$	378		$	315


Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	1.19		$	.51		$	2.23		$	1.88


Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	1.19		$	.51		$	2.23		$	1.88


Weighted Average Common Shares Outstanding
Basic		169			169			169			167
Diluted		170			169			170			168
Dividends Declared per Common Share	$	.59		$	.53		$	1.15		$	1.06

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements Of Financial Position (Unaudited)


	June 30,			December 31,
(in Millions)	2011			2010
ASSETS
Current Assets
Cash and cash equivalents	$	61		$	65
Restricted cash		118			120
Accounts receivable (less allowance for doubtful accounts of $174 and $196, respectively)
Customer		1,297			1,393
Other		151			402
Inventories
Fuel and gas		473			460
Materials and supplies		212			202
Deferred income taxes		127			139
Derivative assets		109			131
Other		223			255

		2,771			3,167


Investments
Nuclear decommissioning trust funds		975			939
Other		526			518

		1,501			1,457


Property
Property, plant and equipment		22,123			21,574
Less accumulated depreciation, depletion and amortization		(8,839	)		(8,582	)

		13,284			12,992


Other Assets
Goodwill		2,020			2,020
Regulatory assets		3,905			4,058
Securitized regulatory assets		656			729
Intangible assets		71			67
Notes receivable		127			123
Derivative assets		49			77
Other		195			206

		7,023			7,280


Total Assets	$	24,579		$	24,896

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)


	June 30,			December 31,
(in Millions, Except Shares)	2011			2010
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	733		$	729
Accrued interest		101			111
Dividends payable		199			95
Short-term borrowings		151			150
Current portion long-term debt, including capital leases		326			925
Derivative liabilities		110			142
Gas inventory equalization		109			—
Other		517			597

		2,246			2,749


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		6,622			6,114
Securitization bonds		559			643
Trust preferred-linked securities		289			289
Capital lease obligations		37			43

		7,507			7,089


Other Liabilities
Deferred income taxes		2,964			2,632
Regulatory liabilities		978			1,328
Asset retirement obligations		1,538			1,498
Unamortized investment tax credit		70			75
Derivative liabilities		74			110
Liabilities from transportation and storage contracts		76			83
Accrued pension liability		680			866
Accrued postretirement liability		1,220			1,275
Nuclear decommissioning		152			149
Other		250			275

		8,002			8,291


Commitments and Contingencies (Notes 6 and 10)

Equity
Common stock, without par value, 400,000,000 shares authorized, 169,328,889 and 169,428,406 shares issued and outstanding, respectively		3,415			3,440
Retained earnings		3,516			3,431
Accumulated other comprehensive loss		(146	)		(149	)

Total DTE Energy Company Equity		6,785			6,722
Noncontrolling interests		39			45

Total Equity		6,824			6,767

Total Liabilities and Equity	$	24,579		$	24,896

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended
	June 30
(in Millions)	2011			2010
Operating Activities
Net income	$	378		$	317
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		493			504
Deferred income taxes		14			72
Asset losses, reserves and impairments, net		8			1
Changes in assets and liabilities, exclusive of changes shown separately (Note 13)		266			257

Net cash from operating activities		1,159			1,151


Investing Activities
Plant and equipment expenditures — utility		(684	)		(463	)
Plant and equipment expenditures — non-utility		(35	)		(52	)
Proceeds from sale of assets, net		9			24
Restricted cash for debt redemption		2			1
Proceeds from sale of nuclear decommissioning trust fund assets		59			128
Investment in nuclear decommissioning trust funds		(76	)		(145	)
Consolidation of VIEs		—			19
Other		(42	)		(4	)

Net cash used for investing activities		(767	)		(492	)


Financing Activities
Issuance of long-term debt		547			—
Redemption of long-term debt		(721	)		(91	)
Short-term borrowings, net		1			(327	)
Issuance of common stock		—			23
Repurchase of common stock		(18	)		—
Dividends on common stock		(190	)		(176	)
Other		(15	)		(16	)

Net cash used for financing activities		(396	)		(587	)


Net Increase (Decrease) in Cash and Cash Equivalents		(4	)		72
Cash and Cash Equivalents at Beginning of Period		65			52

Cash and Cash Equivalents at End of Period	$	61		$	124

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Changes in Equity and
Comprehensive Income (Unaudited)


										Accumulated
										Other
	Common Stock						Retained			Comprehensive			Noncontrolling
(Dollars in Millions, Shares in Thousands)	Shares			Amount			Earnings			Loss			Interest			Total

Balance, December 31, 2010		169,428		$	3,440		$	3,431		$	(149	)	$	45		$	6,767

Net income		—			—			378			—			—			378
Dividends declared on common stock		—			—			(293	)		—			—			(293	)
Repurchase of common stock		(867	)		(42	)		—			—			—			(42	)
Benefit obligations, net of tax		—			—			—			2			—			2
Foreign currency translation, net of tax		—			—			—			1			—			1
Stock-based compensation, distributions to noncontrolling interests and other		768			17			—			—			(6	)		11

Balance, June 30, 2011		169,329		$	3,415		$	3,516		$	(146	)	$	39		$	6,824

The following table displays comprehensive income for the six-month periods ended June 30:


(in Millions)	2011		2010
Net income	$	378	$	317

Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligation, net of taxes of $1 and $2		2		4
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $— and $5		—		10

		2		14


Net unrealized gains (losses) on derivatives:
Gains (losses) during the period, net of taxes of $— and $1		—		1
Amounts reclassified to income, net of taxes of $— and $1		—		1

		—		2


Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $— and $(6)		—		(12	)
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $— and $(5)		—		(10	)

		—		(22	)


Foreign currency translation, net of taxes of $— and $—		1		—


Comprehensive income		381		311
Less: Comprehensive income attributable to noncontrolling interests		—		2

Comprehensive income attributable to DTE Energy Company	$	381	$	309

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

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

	•		MichCon, 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) unconventional gas and oil project development and production; (3) power and industrial projects and coal transportation and marketing; and (4) energy marketing and trading operations.

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

Reference in this report to “we,” “us,” “our,” “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 2010 Annual Report on Form 10-K.

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

The Consolidated Financial Statements are unaudited, but in the Company’s opinion include all adjustments necessary to a fair statement of the results for the interim periods. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2011.

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. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When the Company does not influence the operating policies of an investee, the cost method is used. These consolidated financial statements also reflect the Company’s proportionate interests in certain jointly owned utility plant. The Company eliminates all intercompany balances and transactions.

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

returns of the VIE. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

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

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of June 30, 2011, the carrying amount of assets and liabilities in the Consolidated Statement of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

In 2001, Detroit Edison 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. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated as the Company is the primary beneficiary.

DTE Energy has interests in two unconsolidated trusts that were formed for the purpose of issuing preferred securities and lending the gross proceeds to the Company. The assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments the Company makes are used by the trusts to make cash distributions on the preferred securities it has issued. DTE Energy has reviewed these interests and has determined they are VIEs, but the Company is not the primary beneficiary as it does not have variable interests in the trusts and therefore, the trusts are not 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, 2011 and December 31, 2010. Amounts at June 30, 2011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. Entities, 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, 2011
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	11	$	11	$	—
Restricted cash		106		5		111		111
Accounts receivable		34		16		50		36
Inventories		—		113		113		—
Other current assets		—		1		1		—
Property, plant and equipment		—		60		60		26
Securitized regulatory assets		656		—		656		656
Other assets		12		8		20		20

	$	808	$	214	$	1,022	$	849


LIABILITIES
Accounts payable and accrued current liabilities	$	16	$	63	$	79	$	16
Current portion long-term debt, including capital leases		158		7		165		165
Other current liabilities		59		2		61		61
Mortgage bonds, notes and other		—		32		32		32
Securitization bonds		559		—		559		559
Capital lease obligations		—		21		21		21
Other long term liabilities		6		2		8		8

	$	798	$	127	$	925	$	862


	December 31, 2010
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash		104		8		112		112
Accounts receivable		42		8		50		44
Inventories		—		99		99		—
Other current assets		—		1		1		—
Property, plant and equipment		—		54		54		38
Securitized regulatory assets		729		—		729		729
Other assets		13		9		22		21

	$	888	$	183	$	1,071	$	944


LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases		150		7		157		157
Other current liabilities		62		6		68		66
Mortgage bonds, notes and other		—		35		35		35
Securitization bonds		643		—		643		643
Capital lease obligations		—		23		23		23
Other long term liabilities		6		7		13		12

	$	878	$	105	$	983	$	954

Amounts for non-consolidated VIEs as June 30, 2011 and December 31, 2010 were as follows:


	June 30,		December 31,
(in Millions)	2011		2010
Other investments	$	113	$	98
Note receivable		5		6
Trust preferred — linked securities		289		289

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Emission allowances and renewable energy credits are charged to expense as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $9 million at June 30, 2011 and December 31, 2010. The Company’s intangible assets related to renewable energy credits were $23 million and $17 million at June 30, 2011 and December 31, 2010, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at June 30, 2011 were $64 million and $25 million, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2010 were $63 million and $22 million, respectively. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years.

Income Taxes

The Company’s effective tax rate for the three months ended June 30, 2011 was a negative 14 percent as compared to 34 percent for the three months ended June 30, 2010. The Company’s effective tax rate for the six months ended June 30, 2011 was 17 percent as compared to 34 percent for the six months ended June 30, 2010. The decrease in the effective tax rate in 2011 is due primarily to the recognition of an $88 million income tax benefit due to the enactment of the Michigan Corporate Income Tax which is discussed below.

The Company had $3 million of unrecognized tax benefits at June 30, 2011 and $5 million at December 31, 2010, that, if recognized, would favorably impact its effective tax rate. The Company has increased its unrecognized tax benefit by $40 million in the six months ended June 30, 2011, as a result of a change in a tax position taken during a prior period. During the next twelve months, it is reasonably possible that the Company will settle certain federal tax audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $49 million.

Michigan Corporate Income Tax (MCIT)

On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and will become effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

Effective with the enactment of the MCIT in the second quarter of 2011, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $41 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT.

Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of net deferred tax assets of $307 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $88 million decrease in deferred tax liabilities attributable to our non-utility entities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $88 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy’s unitary Michigan tax return. The $88 million was recognized as a reduction to income tax expense in the second quarter of 2011.

Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statements of Cash Flows.

Offsetting Amounts Related to Certain Contracts

The Company offsets the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting agreement, which reduces both the Company’s total assets and total liabilities. As of June 30, 2011, the total cash collateral posted, net of cash collateral received, was $68 million. Derivative assets and derivative liabilities are shown net of collateral of $6 million and $34 million, respectively. At June 30, 2011, the Company recorded cash collateral received of $4 million and cash collateral paid of $44 million not related to derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

NOTE 3 — FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at June 30, 2011 and December 31, 2010.

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, 2011:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			June 30, 2011
Assets:
Nuclear decommissioning trusts		626			349			—			—			975
Other investments(1)		56			53			—			—			109
Derivative assets:
Foreign currency exchange contracts		—			16			—			(16	)		—
Commodity Contracts:
Natural Gas		1,151			78			10			(1,224	)		15
Electricity		—			367			136			(369	)		134
Other		28			2			7			(28	)		9

Total derivative assets		1,179			463			153			(1,637	)		158

Total	$	1,861		$	865		$	153		$	(1,637	)	$	1,242


Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(26	)	$	—		$	16		$	(10	)
Interest rate contracts		—			(1	)		—			—			(1	)
Commodity Contracts:
Natural Gas		(1,141	)		(187	)		(9	)		1,212			(125	)
Electricity		—			(384	)		(79	)		417			(46	)
Other		(20	)		(2	)		—			20			(2	)

Total derivative liabilities		(1,161	)		(600	)		(88	)		1,665			(184	)

Total	$	(1,161	)	$	(600	)	$	(88	)	$	1,665		$	(184	)

Net Assets as of June 30, 2011	$	700		$	265		$	65		$	28		$	1,058


Assets:
Current	$	818		$	342		$	117		$	(1,168	)	$	109
Noncurrent(3)		1,043			523			36			(469	)		1,133

Total Assets	$	1,861		$	865		$	153		$	(1,637	)	$	1,242

Liabilities:
Current	$	(817	)	$	(430	)	$	(65	)	$	1,202		$	(110	)
Noncurrent		(344	)		(170	)		(23	)		463			(74	)

Total Liabilities	$	(1,161	)	$	(600	)	$	(88	)	$	1,665		$	(184	)

Net Assets as of June 30, 2011	$	700		$	265		$	65		$	28		$	1,058

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			December 31, 2010
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments(1)		56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts		—			20			—			(20	)		—
Commodity Contracts:
Natural Gas		1,846			128			12			(1,960	)		26
Electricity		—			649			117			(589	)		177
Other		68			4			4			(71	)		5

Total derivative assets		1,914			801			133			(2,640	)		208

Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258


Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts		—			(1	)		—			—			(1	)
Commodity Contracts:
Natural Gas		(1,844	)		(263	)		(11	)		1,955			(163	)
Electricity		—			(653	)		(63	)		643			(73	)
Other		(63	)		(8	)		—			66			(5	)

Total derivative liabilities		(1,907	)		(955	)		(74	)		2,684			(252	)

Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)

Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent(3)		1,270			533			84			(760	)		1,127

Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258

Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent		(617	)		(225	)		(53	)		785			(110	)

Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)

Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006


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

(2)		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.

(3)		Includes $109 million and $111 million at June 30, 2011 and December 31, 2010, respectively, of other investments that are included in the Consolidated Statements of Financial Position in Other Investments.

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, 2011 and 2010:


	Three Months Ended June 30, 2011
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of April 1, 2011	$	3		$	8		$	5		$	16
Transfers into Level 3		(3	)		62			—			59
Transfers out of Level 3		—			(2	)		—			(2	)
Total gains or (losses):
Included in earnings		3			8			—			11
Recorded in regulatory assets/liabilities		—			—			4			4
Purchases, issuances, sales and settlements:
Purchases		—			1			—			1
Settlements		(2	)		(20	)		(2	)		(24	)

Net Assets as of June 30, 2011	$	1		$	57		$	7		$	65

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, 2011	$	2		$	2		$	—		$	4


	Three Months Ended June 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of April 1, 2010	$	5		$	89		$	2		$	96
Changes in fair value recorded in income		—			(51	)		—			(51	)
Changes in fair value recorded in regulatory assets/liabilities		—			—			4			4
Purchases, issuances and settlements		(3	)		(21	)		(2	)		(26	)
Transfers in/out of Level 3		—			138			—			138

Net Assets as of June 30, 2010	$	2		$	155		$	4		$	161

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, 2010	$	(3	)	$	(71	)	$	—		$	(74	)


	Six Months Ended June 30, 2011
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of January 1, 2011	$	1		$	54		$	4		$	59
Transfers into Level 3		—			73			—			73
Transfers out of Level 3		1			(25	)		—			(24	)
Total gains or (losses):
Included in earnings		(2	)		(18	)		2			(18	)
Recorded in regulatory assets/liabilities		—			—			3			3
Purchases, issuances, sales and settlements:
Purchases		—			1			—			1
Settlements		1			(28	)		(2	)		(29	)

Net Assets as of June 30, 2011	$	1		$	57		$	7		$	65

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, 2011	$	(1	)	$	(17	)	$	2		$	(16	)


	Six Months Ended June 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value recorded in income		2			83			—			85
Changes in fair value recorded in regulatory assets/liabilities		—			—			3			3
Purchases, issuances and settlements		(5	)		(30	)		(2	)		(37	)
Transfers in/out of Level 3		3			83			—			86

Net Assets as of June 30, 2010	$	2		$	155		$	4		$	161

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, 2010	$	(4	)	$	49		$	—		$	45

Transfers in and transfers out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. For the six months ended June 30, 2011, $25 million of net assets reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2. For the three and six months ended June 30, 2011, $62 million and $73 million, respectively, of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3.

For the three and six months ended June 30, 2010, $138 million and $83 million, respectively, of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3. No significant transfers between Levels 1 and 2 occurred in the three and six months ended June 30, 2011 and 2010.

Nuclear Decommissioning Trusts and Other Investments

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

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.

Fair Value of Financial Instruments

The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 4 for further fair value information on financial and derivative instruments.


	June 30, 2011		December 31, 2010
	Fair Value	Carrying Value	Fair Value	Carrying Value
Long-Term Debt	$8.4 billion	$7.8 billion	$8.5 billion	$8.0 billion

Nuclear Decommissioning Trust Funds

Detroit Edison 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. See Note 5.

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC. See Note 6.

The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary.

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


	June 30,		December 31,
(in Millions)	2011		2010
Fermi 2	$	942	$	910
Fermi 1		3		3
Low level radioactive waste		30		26

Total	$	975	$	939

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						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Realized gains	$	12		$	12		$	26		$	21
Realized losses		(9	)		(11	)		(17	)		(19	)
Proceeds from sales of securities		39			69			59			128

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:


	Fair		Unrealized
(in Millions)	Value		Gains
As of June 30, 2011
Equity securities	$	589	$	100
Debt securities		381		14
Cash and cash equivalents		5		—

	$	975	$	114


As of December 31, 2010
Equity securities	$	572	$	77
Debt securities		361		11
Cash and cash equivalents		6		—

	$	939	$	88

The debt securities at June 30, 2011 and December 31, 2010 had an average maturity of approximately 8 and 6 years, respectively. Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As Detroit Edison 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. Detroit Edison recognized $32 million and $26 million of unrealized losses as Regulatory assets at June 30, 2011 and December 31, 2010, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison 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 for the three and six months ended June 30, 2011 and June 30, 2010 for Fermi 1 trust assets.

Other Available-For-Sale Securities

The following table summarizes the fair value of the Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:


	June 30, 2011				December 31, 2010
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	129	$	129	$	133	$	133
Equity securities		6		6		6		6

As of June 30, 2011, these securities were comprised primarily of money-market funds and equity securities. During the three months ended June 30, 2011 and 2010, no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the period. Gains (losses) related to trading securities held at June 30, 2011 and June 30, 2010 were $4 million and $(2) million, respectively.

NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a 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. For fair value hedges, changes in fair values for the derivative are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

The Company’s primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency exchange. 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 and the coal marketing activities of its Power and Industrial Projects segment. Contracts classified as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, unconventional gas reserves, power transmission, pipeline transportation and certain storage assets.

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

Gas Utility — MichCon purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through March 2014. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are 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, gathering and storage of natural gas. Fixed-priced contracts are used in the marketing and management of transportation, gathering and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional natural gas and oil project development and production. The Company may use derivative contracts to manage changes in the price of natural gas and crude oil.

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method. The segment also engages in coal marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emission allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity and 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 power purchase and sale contracts and 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 2011, 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, 2011 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g., electricity or 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 describe the four 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 sales of gas production and trades associated with power transmission, gas transportation and storage capacity. Changes in the value of derivatives in this category 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 Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison 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, 2011:


(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)

Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	16	$	(26	)
Commodity Contracts:
Natural Gas		1,239		(1,337	)
Electricity		503		(463	)
Other		37		(22	)

Total derivatives not designated as hedging instruments	$	1,795	$	(1,848	)

Total derivatives:
Current	$	1,277	$	(1,312	)
Noncurrent		518		(537	)

Total derivatives	$	1,795	$	(1,849	)


	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,277		$	518		$	(1,312	)	$	(537	)
Counterparty netting		(1,168	)		(463	)		1,168			463
Collateral adjustment		—			(6	)		34			—

Total derivatives as reported	$	109		$	49		$	(110	)	$	(74	)

The following tables present the fair value of derivative instruments as of December 31, 2010:


(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)

Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas		1,986		(2,118	)
Electricity		766		(716	)
Other		76		(71	)

Total derivatives not designated as hedging instruments	$	2,848	$	(2,935	)

Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent		837		(895	)

Total derivatives	$	2,848	$	(2,936	)


	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting		(1,871	)		(760	)		1,871			760
Collateral adjustment		(9	)		—			28			25

Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

The income effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2011 and June 30, 2010 is as follows:


		Gain (Loss)						Gain (Loss)
		Recognized in						Recognized in
		Income on						Income on
	Location of Gain	Derivatives for						Derivatives for
	(Loss) Recognized	Three Months Ended						Six Months Ended
(in Millions)	in Income	June 30						June 30
Derivatives Not Designated As Hedging Instruments	On Derivatives	2011			2010			2011			2010
Foreign currency exchange contracts	Operating Revenue	$	1		$	14		$	(5	)	$	3

Commodity Contracts:
Natural Gas	Operating Revenue		9			17			15			27
Natural Gas	Fuel, purchased power and gas		(4	)		1			(10	)		(6	)
Electricity	Operating Revenue		30			(22	)		29			49
Other	Operating Revenue		2			1			8			1
Other	Operation and maintenance		—			(1	)		—			(1	)

Total		$	38		$	10		$	37		$	73

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were $4 million and $3 million in gains related to FTRs recognized in Regulatory liabilities for the three and six months ended June 30, 2011, respectively.

The following table presents the cumulative gross volume of derivative contracts outstanding as of June 30, 2011:


Commodity	Number of Units
Natural Gas (MMBtu)		567,029,409
Electricity (MWh)		56,162,251
Foreign Currency Exchange ($ CAD)		96,943,647

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of June 30, 2011, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date under both hard trigger and soft trigger provisions was approximately $236 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

NOTE 5 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2011 follows:

(in Millions)


Asset retirement obligations at December 31, 2010	$	1,514
Accretion		46
Liabilities incurred		1
Revision in estimated cash flows		(1	)
Liabilities settled		(7	)

Asset retirement obligations at June 30, 2011		1,553
Less amount included in current liabilities		(15	)

	$	1,538

In 2001, Detroit Edison began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In the first quarter of 2011, based on management decisions revising the timing and estimate of cash flows, Detroit Edison accrued an additional $19 million with respect to the decommissioning of Fermi 1. Subject to NRC notification, management intends to suspend decommissioning activities and place the facility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations. In the second quarter of 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the Detroit Edison asset retirement obligation for asbestos removal with approximately $5.7 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations.

NOTE 6 — REGULATORY MATTERS

2010 Electric Rate Case Filing

Detroit Edison filed a rate case on October 29, 2010 based on a projected 12-month period ending March 31, 2012. The filing with the MPSC requested a $443 million increase in base rates that is required to recover higher costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, inflation, the capital costs of plant additions, the reduction in territory sales, the impact from the expiration of certain wholesale for resale contracts and the increased migration of customers to the electric Customer Choice program. Detroit Edison also proposed certain adjustments which could reduce the net impact on the required increase in rates by approximately $190 million. These adjustments relate to electric Customer Choice migration, pension and other postretirement benefits expenses and the Nuclear Decommissioning surcharge. On April 28, 2011, Detroit Edison self-implemented a rate increase of $107 million. This increase, which is collected subject to refund, will remain in place until a final order is issued.

Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation

In March 2010, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2009 RETM and LCT. The Company’s 2009 restoration and line clearance expenses were less than the amount provided in rates. Accordingly, Detroit Edison proposed a refund of approximately $16 million, including interest. On May 10, 2011, the MPSC issued an order approving the proposed refund and Detroit Edison began applying credits to customer bills in July 2011.

Detroit Edison Choice Implementation Surcharge (CIS)

In June 2011, Detroit Edison filed an application with the MPSC for approval of its CIS reconciliation and proposed refund of $2.4 million.

2009 Detroit Edison Depreciation Filing

In compliance with an MPSC order, Detroit Edison filed a depreciation case in November 2009. On June 16, 2011, the MPSC issued an order reducing Detroit Edison’s composite depreciation rates from 3.33% to 3.06%, effective for accounting purposes, the day after the issuance of the MPSC order in the 2010 rate case expected in October 2011.

Renewable Energy Plan

In June 2011, Detroit Edison filed an amended Renewable Energy Plan with the MPSC requesting authority to continue to recover approximately $100 million of surcharge revenues. The proposed revenues are necessary in order to continue to properly implement Detroit Edison’s 20-year renewable energy plan, to deliver cleaner, renewable electric generation to its customers, to further diversify Detroit Edison’s and the State of Michigan’s sources of electric supply, and to address the state and national goals of increasing energy independence.

Detroit Edison Revenue Decoupling Mechanism (RDM)

In May 2011, Detroit Edison filed an application with the MPSC for approval of its RDM reconciliation for the period February 2010 through January 2011 requesting authority to refund approximately $55.8 million, plus interest.

Power Supply Cost Recovery (PSCR) Proceedings

The PSCR process is designed to allow Detroit Edison to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. Detroit Edison’s power supply costs include fuel 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.

The following table summarizes Detroit Edison’s PSCR reconciliation filing currently pending with the MPSC:

Net Over/(Under)-Recovery,

PSCR Cost of

PSCR Year

Date Filed

Including Interest

Power Sold

2009

March 2010

$15.6 million

$1.2 billion

2010

March 2011

$(52.6) million

$1.2 billion

2010 PSCR Year — The 2010 PSCR reconciliation includes $15.6 million net over-recovery for the 2009 PSCR year. In addition to the net under-recovery of $52.6 million, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing.

2011 Plan Year — In September 2010, Detroit Edison filed its 2011 PSCR plan case seeking approval of a levelized PSCR factor of 2.98 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.2 billion. The plan also includes approximately $36 million for the recovery of its projected 2010 PSCR under-recovery.

Gas Cost Recovery (GCR) Proceedings

The GCR process is designed to allow MichCon to recover all of its gas supply costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

The following table summarizes MichCon’s GCR reconciliation filing currently pending with the MPSC:


		Net Over-Recovery,
GCR Year	Date Filed	Including Interest	GCR Cost of Gas Sold
2009-2010	June 2010	$5.9 million	$1.0 billion
2010-2011	June 2011	$1.0 million	$0.7 billion

2011-2012 Plan Year — In December 2010, MichCon filed its GCR plan case for the 2011-2012 GCR plan year. MichCon filed for a maximum base GCR factor of $5.89 per Mcf adjustable monthly by a contingency factor.

Other

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

NOTE 7 — 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.


	Three Months					Six Months
	Ended June 30					Ended June 30
(in Millions, except per share amounts)	2011		2010			2011		2010
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	202	$	86		$	378	$	315


Average number of common shares outstanding		169		169			169		167

Weighted average net restricted shares outstanding		1		1			1		1


Dividends declared — common shares	$	99	$	89		$	194	$	177
Dividends declared — net restricted shares		—		—			—		1

Total distributed earnings	$	99	$	89		$	194	$	178

Net income less distributed earnings	$	103	$	(3	)	$	184	$	137


Distributed (dividends per common share)	$	.59	$	.53		$	1.15	$	1.06
Undistributed		.60		(.02	)		1.08		.82

Total Basic Earnings per Common Share	$	1.19	$	.51		$	2.23	$	1.88


Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	202	$	86		$	378	$	315


Average number of common shares outstanding		170		169			170		167
Average incremental shares from assumed exercise of options		—		—			—		1

Common shares for dilutive calculation		170		169			170		168


Weighted average net restricted shares outstanding		1		1			1		1


Dividends declared — common shares	$	99	$	89		$	194	$	177
Dividends declared — net restricted shares		—		—			—		1

Total distributed earnings	$	99	$	89		$	194	$	178

Net income less distributed earnings	$	103	$	(3	)	$	184	$	137


Distributed (dividends per common share)	$	.59	$	.53		$	1.15	$	1.06
Undistributed		.60		(.02	)		1.08		.82

Total Diluted Earnings per Common Share	$	1.19	$	.51		$	2.23	$	1.88

Options to purchase approximately 0.4 million shares of common stock as of June 30, 2010 were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 8 — LONG-TERM DEBT

Debt Issuances

In 2011, the Company remarketed or issued the following long-term debt:

(in Millions)


Company	Month Issued	Type	Interest Rate			Maturity		Amount
Detroit Edison	April	Tax-Exempt Revenue Bonds(1)(2)		2.35	%		2024	$	31
Detroit Edison	May	Mortgage Bonds (3)		3.90	%		2021		250
DTE Energy	May	Senior Notes(4)	Variable(5)				2013		300

								$	581


(1)		These bonds were remarketed in a long-term rate mode with a three-year term ending April 1, 2014. The final maturity of the issue is October 1, 2024.

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

(3)		Proceeds were used for general corporate purposes.

(4)		Proceeds were used to repay a portion of DTE Energy’s $600 million 7.05% Senior Notes due June 1, 2011 and for general corporate purposes.

(5)		The interest rate is reset quarterly at the three month LIBOR rate plus 70 basis points.

In June 2011, Detroit Edison agreed to issue and sell $225 million of general and refunding mortgage bonds, with an average rate of 4.6% and an average maturity of 17 years, to a group of institutional investors in a private placement transaction. The bonds are expected to close and fund on September 1, 2011.

Debt Retirements and Redemptions

In 2011, the following debt was retired:

(in Millions)


Company	Month Retired	Type	Interest Rate			Maturity		Amount
Detroit Edison	May	Tax-Exempt Revenue Bonds		6.95	%		2011	$	26
DTE Energy	June	Senior Notes		7.05	%		2011		600

								$	626

NOTE 9 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon have entered into unsecured revolving credit facilities with similar terms with a syndicate of 23 banks that may 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 8.25% 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 above 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 MichCon 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, 2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon were 0.49 to 1, 0.53 to 1 and 0.46 to 1, respectively, and were in compliance with this financial covenant. The availability under these combined facilities at June 30, 2011 is shown in the following table:


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Unsecured revolving credit facility, expiring August 2012	$	538	$	212	$	250	$	1,000
Unsecured revolving credit facility, expiring August 2013		562		63		175		800
Unsecured letter of credit facility, expiring in May 2013		50		—		—		50
Unsecured letter of credit facility, expiring in August 2015		125		—		—		125

Total credit facilities at June 30, 2011	$	1,275	$	275	$	425	$	1,975

Amounts outstanding at June 30, 2011:
Commercial paper issuances		44		107		—		151
Letters of credit outstanding at June 30, 2011		119		—		—		119

		163		107		—		270

Net availability at June 30, 2011	$	1,112	$	168	$	425	$	1,705

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

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, 2011, a $15 million letter of credit was in place, raising the capacity under this facility to $115 million. The $15 million letter of credit is included in the table above. The amount outstanding under this agreement was $23 million and $39 million at June 30, 2011 and December 31, 2010, respectively.

NOTE 10 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to the EPA ozone 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. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of over $205 million in 2011 and up to $2.0 billion of additional capital expenditures through 2020 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The EPA’s proposed National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric Utility Steam Generating Units rule (covering mercury and other air pollutants) was issued on March 16, 2011 for review and comment. The EPA will be accepting input on the proposal and may modify it prior to finalization, scheduled for November 2011. Also, on July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which replaces the Clean Air Interstate Rule (CAIR), requiring further reductions of sulfur dioxides and nitrogen oxides. DTE Energy is reviewing potential impacts of the proposed and recently finalized rules, but is not able to quantify the financial impact of these and other expected rulemakings at this time.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States 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 Detroit Edison, 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 Detroit Edison 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 Detroit Edison 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 Detroit Edison’s fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA’s motion for preliminary injunction was denied and the liability phase of the civil suit has been scheduled for trial in September 2011.

DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the civil action, Detroit Edison could also 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. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

Water — In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $80 million in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA’s use of this provision in determining best technology available for reducing environmental impacts. On March 28, 2011, the EPA issued a proposed rule. A final rule is scheduled to be issued in mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the financial impacts of these developing requirements.

Contaminated 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. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, 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, 2011 and December 31, 2010, the Company had $9 million accrued for remediation. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows.

Landfill — Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction.

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 on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as

defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the financial impact of those proposed rules at this time.

Gas Utility

Contaminated Sites — Gas Utility owns, or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of June 30, 2011 and December 31, 2010, the Company had $37 and $36 million, respectively, accrued for remediation.

Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a 10-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 affiliates 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 Notice of Violation in June of 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 financial 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 financial impact of this investigation.

The Company is also in the process of settling historical air and water violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the financial impact of this settlement. The Company received two notices of violation from the Pennsylvania Department of Environmental Protection 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 and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $1 million on the existing waste water treatment system to comply with existing water discharge requirements. The Company may spend an additional $13 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.

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

Other

In 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (MACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines. This new set of regulations may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The new MACT regulations for industrial boilers provide three years for compliance with the major and area source standards. The Company is currently assessing the impact on current operations to determine the financial impact, if any, to comply with the new standards.

In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. On October 15, 2009, the U.S. District Court granted defendants’ motions dismissing all of plaintiffs’ federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs’ state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.

Nuclear Operations

Property Insurance

Detroit Edison 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.

Detroit Edison 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.

Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.

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, Detroit Edison could be liable for maximum assessments of up to approximately $29 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As of January 1, 2011, as required by federal law, Detroit Edison maintains $375 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is accounted for as a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository and the proposed fiscal year 2011 federal budget recommends termination of funding for completion of the government’s long-term storage facility. Detroit Edison 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. Detroit Edison currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. In 2011, the Company expects to begin loading spent nuclear fuel into an on-site dry cask storage facility which is expected to provide sufficient storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

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 $10 million at June 30, 2011.

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, 2011, the Company had approximately $14 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 5,000 represented employees. In the 2011 second quarter, a new three-year agreement was ratified covering approximately 400 represented employees. The majority of the remaining represented employees are under contracts that expire August 2012 and June and October 2013.

Purchase Commitments

As of June 30, 2011, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5 billion from 2011 through 2051.

The Company also estimates that 2011 capital expenditures will be approximately $1.7 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

Other Contingencies

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

See Notes 4 and 6 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 11 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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


							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Three Months Ended June 30
Service cost	$	18		$	16		$	17		$	14
Interest cost		50			51			31			31
Expected return on plan assets		(61	)		(65	)		(23	)		(18	)
Amortization of:
Net actuarial loss		33			25			15			13
Prior service cost		1			1			(6	)		(1	)
Net transition liability		—			—			—			1
Special termination benefits		2			—			—			—

Net periodic benefit cost	$	43		$	28		$	34		$	40


							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Six Months Ended June 30
Service cost	$	37		$	32		$	34		$	30
Interest cost		101			101			62			63
Expected return on plan assets		(123	)		(129	)		(47	)		(37	)
Amortization of:
Net actuarial loss		66			50			30			27
Prior service cost		2			2			(13	)		(2	)
Net transition liability		—			—			1			1
Special termination benefits		2			—			—			—

Net periodic benefit cost	$	85		$	56		$	67		$	82

Pension and Other Postretirement Contributions

In January 2011, the Company contributed $200 million to its pension plans.

In January 2011, the Company contributed $81 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $90 million contribution to its other postretirement benefit plans by the end of 2011.

NOTE 12 — STOCK-BASED COMPENSATION

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


	Three Months Ended
	June 30
(in Millions)	2011		2010
Stock-based compensation expense	$	11	$	13
Tax benefit		4		5
Stock-based compensation cost capitalized in property, plant and equipment		1		1


	Six Months Ended
	June 30
(in Millions)	2011		2010
Stock-based compensation expense	$	29	$	29
Tax benefit		11		11
Stock-based compensation cost capitalized in property, plant and equipment		2		2

Stock Options

The following table summarizes our stock option activity for the six months ended June 30, 2011:


				Weighted		(in Millions)
				Average		Aggregate
	Number of			Exercise Price		Intrinsic
	Options			Per Share		Value
Options outstanding at January 1, 2011		4,827,457		$	41.09
Granted		—		$	—
Exercised		(1,450,974	)	$	40.55
Forfeited or expired		(21,288	)	$	43.47

Options outstanding at June 30, 2011		3,355,195		$	41.30	$	29.72

Options exercisable at June 30, 2011		2,688,709		$	42.23	$	21.33

As of June 30, 2011, the weighted average remaining contractual life for the exercisable shares was 4.59 years. As of June 30, 2011, 666,486 options were non-vested. During the six months ended June 30, 2011, 687,061 options vested.

The intrinsic value of options exercised for the six months ended June 30, 2011 was $14 million. Total option expense recognized was $1 million and $2 million for the six months ended June 30, 2011 and 2010, respectively.

Restricted Stock Awards

The following summarizes stock awards activity for the six months ended June 30, 2011:


				Weighted Average
				Grant Date
	Restricted			Fair Value
	Stock			Per Share
Balance at January 1, 2011		757,414		$	37.32
Grants		380,840		$	47.98
Forfeitures		(18,692	)	$	38.24
Vested and issued		(263,237	)	$	39.60

Balance at June 30, 2011		856,325		$	41.42

Performance Share Awards

The following summarizes performance share activity for the six months ended June 30, 2011:


	Performance Shares
Balance at January 1, 2011		1,527,253
Grants		597,372
Forfeitures		(12,096	)
Payouts		(467,688	)

Balance at June 30, 2011		1,644,841

Unrecognized Compensation Cost

As of June 30, 2011, the Company had $68 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. These costs are expected to be recognized over a weighted-average period of 1.53 years.

NOTE 13 — SUPPLEMENTAL CASH FLOW INFORMATION

The following table details the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows, and supplementary non-cash information:


	Six Months Ended
	June 30
(in Millions)	2011			2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	65		$	260
Inventories		(23	)		(34	)
Accrued/prepaid pensions		(187	)		(99	)
Accounts payable		27			7
Income taxes receivable/payable		242			40
Derivative assets and liabilities		(20	)		(62	)
Gas inventory equalization		109			68
Postretirement obligation		(55	)		17
Other assets		202			98
Other liabilities		(94	)		(38	)

	$	266		$	257


Noncash financing activities:
Common stock issued for employee benefit plans	$	1		$	136

NOTE 14 — SEGMENT INFORMATION

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

Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan.

Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity. 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.

Unconventional Gas Production is engaged in unconventional gas and oil project development and production.

Power and Industrial Projects is comprised of coke batteries and pulverized coal projects, reduced emission fuel and steel industry fuel-related projects, on-site energy services, renewable power generation, landfill gas recovery and coal transportation, marketing and trading.

Energy Trading consists of energy marketing and trading operations.

Corporate & 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 MBT provision of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various tax credits and net operating losses if applicable. See Note 2 for a discussion of the MCIT, which replaces the MBT effective January 1, 2012. The subsidiaries record federal and state income taxes payable to or receivable from DTE Energy based on the federal and state 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 power sales, gas sales and coal transportation services in the following segments:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Electric Utility	$	9		$	9		$	18		$	15
Gas Utility		1			(1	)		1			—
Gas Storage and Pipelines		4			1			6			2
Power and Industrial Projects		63			70			89			72
Energy Trading		15			18			37			44
Corporate & Other		(11	)		(12	)		(28	)		(33	)

	$	81		$	85		$	123		$	100

Financial data of the business segments follows:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Operating Revenues
Electric Utility	$	1,240		$	1,208		$	2,433		$	2,354
Gas Utility		242			232			931			987
Gas Storage and Pipelines		23			21			48			42
Unconventional Gas Production		10			8			18			16
Power and Industrial Projects		287			291			522			543
Energy Trading		306			117			628			403
Corporate & Other		1			—			2			—
Reconciliation & Eliminations		(81	)		(85	)		(123	)		(100	)

Total	$	2,028		$	1,792		$	4,459		$	4,245


Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	103		$	87		$	188		$	178
Gas Utility		(3	)		19			80			98
Gas Storage and Pipelines		14			10			29			24
Unconventional Gas Production		(1	)		(2	)		(3	)		(5	)
Power and Industrial Projects		5			22			15			40
Energy Trading		12			(26	)		14			12
Corporate & Other (1)		72			(24	)		55			(32	)

Net Income Attributable to DTE Energy	$	202		$	86		$	378		$	315


(1)		The 2011 net income for Corporate & Other includes an income tax benefit of $88 million related to the enactment of the MCIT in the second quarter of 2011. See Note 2.

Part I — Item 2.

DTE ENERGY COMPANY
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 Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

Net income attributable to DTE Energy in the second quarter of 2011 was $202 million, or $1.19 per diluted share, compared to net income attributable to DTE Energy of $86 million, or $0.51 per diluted share, in the second quarter of 2010. Net income attributable to DTE Energy in the six months ended June 30, 2011 was $378 million, or $2.23 per diluted share, compared to net income attributable to DTE Energy of $315 million, or $1.88 per diluted share, in the comparable period of 2010. The increases in net income are primarily due to an income tax benefit of $88 million in the Corporate & Other segment related to the enactment of the MCIT in the second quarter of 2011. See Note 2 of the Notes to Consolidated Financial Statements.

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

The items discussed below influenced our current financial performance and/or may affect future results.

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

UTILITY OPERATIONS

Our Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan. In July 2011, Detroit Edison notified the NRC that it intends to apply for renewal of the operating license for the Fermi 2 nuclear power plant. The current license expires in 2025 and NRC approval of the application would permit the plant to operate an additional 20 years. The application is expected to be filed with the NRC in 2014.

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

Detroit Edison has experienced decreased electric sales in 2011 driven by lower interconnection and industrial sales, partially offset by higher residential and commercial sales. Interconnection sales are lower due primarily to lower power plant generation, while industrial sales are lower due to decreased demand from customers in the automotive and steel industries and their related suppliers and other ancillary businesses. The residential sales increase is primarily a result of weather related usage. MichCon’s sales were higher due to colder winter weather, partially offset by a decrease in the number of customers, reduced natural gas usage by customers due to economic conditions and an increased emphasis on conservation of energy usage.

Both utilities have exposure to the collectability of receivables in our market area. The Company continues to work with our customers through a variety of proactive programs to assist them. We also partner with federal, state and local officials to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low-income customers will affect the level of uncollectible expense. To mitigate volatility of changes in the uncollectible expense, both utilities have uncollectible tracking mechanisms that enable them to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in their last rate cases. The uncollectible tracking mechanisms require annual reconciliation proceedings before the MPSC.


	Six Months Ended
	June 30
(in Millions)	2011		2010
Uncollectible Expense
Detroit Edison	$	18	$	23
MichCon		25		40

	$	43	$	63

We are continuing our efforts to identify opportunities to improve cash flow at our utilities through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects. We are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength. See the Capital Resources and Liquidity section in this Management’s Discussion and Analysis for further discussion of our liquidity outlook.

NON-UTILITY OPERATIONS

We have significant investments in non-utility businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. 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 in the future. We believe that expansion of these businesses will also result in our ability to further diversify geographically.

Gas Storage and Pipelines owns partnership interests in two natural gas storage fields and two interstate pipelines serving the Midwest, Ontario and Northeast markets. Much of the growth in demand for natural gas is expected to occur in the Eastern Canada and the Northeast U.S. regions. We believe that the Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. In addition, we believe that Millennium Pipeline is well positioned for growth related to production from the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York.

Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production primarily within the Barnett shale in north Texas. Our acreage covers an area that produces high BTU gas which provides a significant contribution to revenues from the value of natural gas liquids extracted from the gas stream. During this period of low natural gas prices, these natural gas liquids, with prices correlated to crude oil prices, have provided a significant increase to our realized wellhead price. Our drilling efforts have and will continue to target liquids rich gas and oil producing locations. We continue to develop our holdings and to seek opportunities for additional monetization of select properties when conditions are appropriate.

Power and Industrial Projects is comprised primarily of projects that deliver energy, products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity generated from biomass-fired energy projects. This business segment provides services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. Renewable energy, environmental and economic trends are creating growth opportunities. We believe that the increasing number of states with renewable portfolio standards provides the opportunity to market the expertise of the Power and Industrial Projects segment in on-site energy management, waste-wood power generation, reduced emission fuel, landfill gas and other related services.

Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers’ behalf.

CAPITAL INVESTMENTS

Our utility businesses require significant capital investments each year in order to maintain and improve the reliability of their asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. In addition, significant capital investments are required to comply with increasingly stringent environmental requirements. For both Detroit Edison and MichCon, we plan to seek regulatory approval in general rate case filings to include these capital expenditures within our regulatory rate base consistent with prior general rate case filing treatment.

Detroit Edison is required to implement a 20-year renewable energy plan to address the provisions of Michigan Public Act 295 of 2008, with the goals of delivering cleaner renewable electric generation to its customers, further diversifying Detroit Edison’s and the State of Michigan’s sources of electric supply and addressing the state and national goals of increasing energy independence. Detroit Edison will seek separate regulatory approval and recovery of these renewable capital expenditures within our regulatory rate base through our renewable energy plan filings.

MichCon was required in its 2010 rate order to file two infrastructure improvement cases. MichCon filed a 10-year gas main renewal case for approximately $17 million per year and also filed a 10-year meter move out case for approximately $22 million per year. MichCon is seeking recovery of the costs resulting from these two programs with the MPSC.

In April 2010, the Company signed an agreement with the U.S. Department of Energy for a grant of approximately $84 million in matching funds on total anticipated spending of approximately $168 million related to the accelerated deployment of smart grid technology in Michigan through 2012. The smart grid technology includes the establishment of an advanced metering infrastructure and other technologies that address improved electric distribution service.

Non-utility investments are expected primarily in Gas Storage and Pipeline assets and renewable opportunities in the Power and Industrial Projects businesses.

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 Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the civil action, the Company could also 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.

Manufactured Gas Plant (MGP) and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as MGP sites. Gas Utility owns, or previously owned, 15 such former MGP sites. Detroit Edison owns, or previously owned, three former MGP sites. In addition to the MGP sites, we are also in the process of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash storage facility, electrical distribution substations, gas pipelines, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years.

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 on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either, to designate coal ash as a “Hazardous Waste” as defined by RCRA or to regulate coal ash as non-hazardous waste under RCRA. However, agencies and legislatures

have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA were to designate 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. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the financial impact of those expected rulemakings at this time.

Non-Utility

The Company’s non-utility affiliates 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 Notice of Violation in June of 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 financial 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 financial impact of this investigation. The Company is also in the process of settling historical air and water violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the financial impact of this settlement. The Company is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment for the coke battery facility located in Pennsylvania. This upgrade is expected to be completed over the next two years to meet future regulatory requirements.

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

Other

Global Climate Change

The EPA has promulgated the Greenhouse Gas Tailoring rule that regulates greenhouse gases as pollutants under the EPA’s new source permitting and major source operating permit programs, and that requires a Best Available Control Technology (BACT) determination for new and modified major sources of greenhouse gas (GHG). In addition, the EPA will be issuing proposed GHG performance standards for new and modified electric generating units in late 2011. Comprehensive climate change and energy legislation was passed out of the U.S. House in 2009, but the Senate was unable to agree on passage of a climate bill. In the current U.S. Congress, efforts are focused on delaying the EPA’s regulation of GHGs with no expectation of enacting a comprehensive national climate program. Pending or future regulatory or legislative actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify the financial impacts on DTE Energy or its customers at this time.

OUTLOOK

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

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

	•		improving Electric and Gas Utility customer satisfaction;

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

	•		managing the growth of our utility asset base with consideration of customer affordability;

	•		optimizing our cost structure across all business segments;

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

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

We will continue to pursue opportunities to grow our businesses in a disciplined manner by securing 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.

Net income attributable to DTE Energy by segment for the three and six months ended June 30, 2011 and 2010 is as follows:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	103		$	87		$	188		$	178
Gas Utility		(3	)		19			80			98
Gas Storage and Pipelines		14			10			29			24
Unconventional Gas Production		(1	)		(2	)		(3	)		(5	)
Power and Industrial Projects		5			22			15			40
Energy Trading		12			(26	)		14			12
Corporate & Other		72			(24	)		55			(32	)

Net Income Attributable to DTE Energy	$	202		$	86		$	378		$	315

ELECTRIC UTILITY

Our Electric Utility segment consists principally of Detroit Edison.

Electric Utility results are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	1,240		$	1,208		$	2,433		$	2,354
Fuel and Purchased Power		417			390			795			733

Gross Margin		823			818			1,638			1,621
Operation and Maintenance		330			326			660			635
Depreciation and Amortization		204			210			407			414
Taxes Other Than Income		60			61			119			126
Asset (Gains) and Losses, Net		(5	)		—			14			(1	)

Operating Income		234			221			438			447
Other (Income) and Deductions		68			79			135			158
Income Tax Provision		63			55			115			111

Net Income Attributable to DTE Energy Company	$	103		$	87		$	188		$	178

Operating Income as a Percentage of Operating Revenues		19	%		18	%		18	%		19	%

Gross margin increased $5 million in the second quarter of 2011 and $17 million in the six-month period ended June 30, 2011. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:


(in Millions)	Three Months			Six Months
Base sales, net of RDM and CIM	$	20		$	30
Securitization bond and tax surcharge		(13	)		(15	)
Electric Choice implementation surcharge elimination		(6	)		(11	)
Energy optimization incentive		—			9
Restoration tracker		1			6
Other		3			(2	)

Increase in gross margin	$	5		$	17

Three Months Ended

Six Months Ended

June 30

(in Thousands of MWh)

2011

2010

2011

2010

Electric Sales

Residential

3,607

3,602

7,495

7,267

Commercial

3,998

3,988

7,991

7,930

Industrial

2,405

2,605

4,747

5,081

Other

763

799

1,560

1,600

10,773

10,994

21,793

21,878

Interconnection sales (1)

1,156

1,450

1,461

2,760

Total Electric Sales

11,929

12,444

23,254

24,638

Electric Deliveries

Retail and Wholesale

10,773

10,994

21,793

21,878

Electric Customer Choice, including self generators (2)

1,409

1,283

2,711

2,386

Total Electric Sales and Deliveries

12,182

12,277

24,504

24,264


(1)		Represents power that is not distributed by Detroit Edison.

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

Power Generated and Purchased


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Thousands of MWh)	2011			2010			2011			2010
Power Plant Generation
Fossil		8,807			9,595			16,864			19,115
Nuclear		2,408			2,087			4,114			4,287

		11,215			11,682			20,978			23,402
Purchased Power		1,573			1,474			4,050			2,796

System Output		12,788			13,156			25,028			26,198
Less Line Loss and Internal Use		(859	)		(712	)		(1,774	)		(1,560	)

Net System Output		11,929			12,444			23,254			24,638

Average Unit Cost ($/MWh) Generation (1)	$	21.85		$	18.96		$	21.36		$	18.87

Purchased Power	$	44.65		$	45.60		$	42.29		$	39.31

Overall Average Unit Cost	$	24.66		$	21.95		$	24.75		$	21.05


(1)		Represents fuel costs associated with power plants.

Operation and maintenance expense increased $4 million and $25 million in the three and six months ended June 30, 2011, respectively. The increase for the 2011 second quarter is primarily due to higher energy optimization and renewable energy expenses of $5 million, partially offset by lower restoration and line clearance expenses of $2 million. The increase for the 2011 six-month period is attributable to increased power plant generation expenses of $15 million, higher energy optimization and renewable energy expenses of $9 million and higher employee benefit related expenses of $8 million, partially offset by reduced uncollectible expenses of $5 million.

Asset (gains) and losses, net increased $5 million and decreased $15 million in the three and six months ended June 30, 2011, respectively. The changes in the six month periods are primarily attributable to an accrual of $19 million in the first quarter of 2011 resulting from management’s revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by second quarter 2011 revisions in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation. See Note 5 of the Notes to the Consolidated Financial Statements.

Outlook — We continue to move forward in our efforts to improve the operating performance and cash flow of Detroit Edison. The 2010 MPSC order provided for an uncollectible expense tracking mechanism which financially assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions, weather and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility. We expect that our planned significant environmental and renewable energy investments will result in earnings growth. Looking forward, additional factors may impact earnings such as the outcome of the 2010 electric rate case and other regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs, lower levels of wholesale sales due to contract expirations, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	242		$	232		$	931		$	987
Cost of Gas		95			83			501			547

Gross Margin		147			149			430			440
Operation and Maintenance		103			69			204			178
Depreciation and Amortization		22			22			44			48
Taxes Other Than Income		14			14			31			31

Operating Income		8			44			151			183
Other (Income) and Deductions		13			14			26			30
Income Tax Provision (Benefit)		(2	)		11			45			55

Net Income (Loss) Attributable to DTE Energy Company	$	(3	)	$	19		$	80		$	98

Operating Income as a Percentage of Operating Revenues		3	%		19	%		16	%		19	%

Gross margin decreased $2 million in the second quarter of 2011 and $10 million in the six-month period ended June 30, 2011. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:


(in Millions)	Three Months			Six Months
Weather	$	15		$	41
Uncollectible tracking mechanism		(13	)		(36	)
2010 self-implementation and rate order		5			(16	)
Revenue decoupling mechanism		(1	)		9
Energy optimization revenue and incentive		2			9
Midstream storage and transportation revenues		(4	)		(9	)
Transfer of subsidiaries to Gas Storage and Pipelines segment		(4	)		(8	)
Other		(2	)		—

Decrease in gross margin	$	(2	)	$	(10	)


	Three Months Ended				Six Months Ended
	June 30				June 30
(in Millions)	2011		2010		2011		2010
Gas Markets
Gas sales	$	162	$	153	$	733	$	791
End user transportation		40		33		117		106

		202		186		850		897
Intermediate transportation		14		16		29		31
Storage and other		26		30		52		59

	$	242	$	232	$	931	$	987

Gas Markets (in Bcf)
Gas sales		18		14		80		71
End user transportation		27		28		79		72

		45		42		159		143
Intermediate transportation		62		108		145		207

		107		150		304		350

Operation and maintenance expense increased $34 million and $26 million in the three and six months ended June 30, 2011, respectively. The increases for the 2011 periods are due primarily to the 2010 deferral of $32 million of previously expensed CTA restructuring expenses. The second quarter of 2011 was also impacted by higher energy optimization expenses of $2 million. The 2011 six month period also included higher energy optimization expenses of $5 million and increased maintenance and service repair expenses of $4 million, partially offset by lower uncollectible expenses of $15 million.

Outlook — We continue to move forward in our efforts to improve the operating performance and cash flow of Gas Utility. Unfavorable economic trends have resulted in a decrease in the number of customers in our service territory, increased customer conservation and continued high levels of theft and uncollectible accounts receivable. The MPSC has provided for an uncollectible expense tracking mechanism which assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility in the future. Looking forward, additional factors may impact earnings such as infrastructure improvement capital programs, the outcome of future regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity, minimize lost and stolen gas, 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
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	23		$	21		$	48		$	42
Operation and Maintenance		3			4			7			8
Depreciation and Amortization		2			2			3			3
Taxes Other Than Income		1			1			2			1

Operating Income		17			14			36			30
Other (Income) and Deductions		(6	)		(2	)		(13	)		(10	)
Income Tax Provision		8			6			18			15

Net Income		15			10			31			25
Noncontrolling Interest		1			—			2			1

Net Income Attributable to DTE Energy Company	$	14		$	10		$	29		$	24

Net income attributable to Gas Storage and Pipelines increased $4 million and $5 million in the three and six months ended June 30, 2011, respectively. The 2011 second quarter increase was primarily driven by earnings from two operating subsidiaries that were transferred from an affiliate effective January 1, 2011 and increased earnings from equity investments. The year to date 2011 increase was primarily driven by earnings from the two transferred subsidiaries and a settlement for customer gas treating services performed in prior years.

Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. Millennium Pipeline has secured customers for its Phase 1 & 2 expansions which are scheduled to be in-service in the fourth quarter of 2012 and the fourth quarter of 2013, respectively. Millennium’s total capacity with the Phase 1 & 2 expansion will increase from 525,000 dth/d to over 800,000 dth/d. In addition, DTE has executed an agreement with Southwestern Energy Services Company to support its Bluestone lateral and gathering system. Bluestone is a 37 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow over 250,000 dth/d to both Millennium Pipeline and Tennessee Pipeline and is scheduled to be in-service in the second quarter of 2012. DTE plans to spend up to $280 million over the next five years on the Bluestone lateral and gathering system.

UNCONVENTIONAL GAS PRODUCTION

Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production primarily within the Barnett shale in northern Texas.

Unconventional Gas Production results are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	10		$	8		$	18		$	16
Operation and Maintenance		6			4			10			8
Depreciation, Depletion and Amortization		5			4			9			8
Taxes Other Than Income		—			1			1			1
Asset (Gains) and Losses, Net		—			—			—			4

Operating Loss		(1	)		(1	)		(2	)		(5	)
Other (Income) and Deductions		1			2			3			3
Income Tax Benefit		(1	)		(1	)		(2	)		(3	)

Net Loss Attributable to DTE Energy Company	$	(1	)	$	(2	)	$	(3	)	$	(5	)

Unconventional Gas Production results, for the six month period, were slightly favorable primarily due to a $4 million impairment of expired or expiring leasehold positions in 2010. Both revenues and expenses increased as a result of new wells on line, increased liquids prices and higher crude oil production.

Outlook — In the longer-term, we plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties when conditions are appropriate. Our strategy for 2011 is to maintain our focus on optimizing the productivity of our wells, which adds value to our asset base. Given the continued outlook of low natural gas prices, drilling efforts will continue to target liquids rich gas and oil production. During 2011, we expect total capital investment of $25 million to drill approximately 20 new wells and continue to acquire select acreage and achieve production of approximately 5.5 Bcfe of natural gas, compared with 5 Bcfe in 2010.

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; provide coal transportation services and marketing; and sell electricity generated from biomass-fired energy projects.

Power and Industrial Projects results are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	287		$	291		$	522		$	543
Operation and Maintenance		261			250			467			464
Depreciation and Amortization		14			14			29			29
Taxes Other Than Income		1			3			5			7
Asset (Gains) Losses and Reserves and Impairments, Net		3			(2	)		(6	)		(4	)

Operating Income		8			26			27			47
Other (Income) and Deductions		5			2			8			5
Income Taxes
Provision		2			10			8			17
Production Tax Credits		(2	)		(9	)		(3	)		(16	)

		—			1			5			1

Net Income		3			23			14			41
Noncontrolling Interests		(2	)		1			(1	)		1

Net Income Attributable to DTE Energy Company	$	5		$	22		$	15		$	40

Operating revenues decreased $4 million and $21 million in the three and six months ended June 30, 2011, respectively. The decrease in the second quarter of 2011 is primarily due to $57 million of lower coal transportation and marketing services primarily due to the expiration of our long-term rail transportation contract, offset by a $17 million increase in coke demand and pricing and a $36 million increase primarily related to reduced emission fuels projects. The decrease in the six-month period is primarily due to $100 million of coal transportation and marketing services primarily due to the expiration of our long-term rail transportation contract, offset by a $40 million increase in coke demand and pricing and a $39 million increase primarily related to reduced emission fuels projects.

Operation and maintenance expense increased $11 million and $3 million in the three and six months ended June 30, 2011, respectively. The increase in the second quarter of 2011 is primarily due to a $23 million increase in coke production and higher coal costs and a $33 million increase primarily related to reduced emission fuels projects, partially offset by $45 million of lower coal transportation and marketing services primarily due to the expiration of our long-term rail transportation contract. The increase in the six-month period is primarily due to $52 million increase in coke production and higher coal costs and a $37 million increase primarily related to reduced emission fuels projects, partially offset by $86 million of lower coal transportation and marketing services primarily due to the expiration of our long-term rail transportation contract.

Asset (Gains) Losses were lower by $5 million and higher by $2 million in the three and six months ended June 30, 2011, respectively. The decrease in the second quarter and year to date is primarily due to a $9 million asset impairment, offset by gains of $4 million related to reduced emission fuels projects.

Production tax credits were lower by $7 million and $13 million in the three and six months ended June 30, 2011, respectively, due primarily to expiration of steel industry fuels credits as of December 31, 2010.

Outlook — We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2011. During 2010 we experienced higher margins from coke sales due to premium pricing and lower coal costs. In 2011 we have returned to normal margin levels. The tax credits associated with our steel industry fuels facilities expired at December 31, 2010 which generated approximately $29 million in 2010. We supply on-site energy services to the domestic automotive manufacturers who have also experienced stabilized demand for automobiles. In March 2011, the Company acquired a cogeneration facility and will provide electricity and steam to customers in the chemical industry.

In late 2009, we began operating five reduced emission fuel facilities located at Detroit Edison owned coal-fired power plants. We have begun construction on two additional facilities at another Detroit Edison owned power plant and we are in advanced negotiations to construct facilities at third party owned power plants. The facilities reduce Nitrogen Oxides (NOX) and Mercury (Hg) emissions and qualify for production tax credits when the fuel is sold to an unrelated party through 2019. Qualifying facilities are eligible to generate tax credits for ten years. We continue to optimize these facilities by seeking investors for facilities operating at Detroit Edison sites and intend to relocate or construct other facilities at alternative sites which may provide increased production and emission reduction opportunities in 2011 and future years. In January 2011, the Company sold a membership interest in one of these reduced emission fuel facilities that is located at a Detroit Edison site.

Environmental and economic trends are creating growth opportunities for renewable power. The increasing number of states with renewable portfolio standards provides investment opportunities in waste-wood power generation. In addition to the three facilities in operation, we expect to convert and place into service additional facilities in 2011 and 2013. We will continue to look for additional investment opportunities for waste-wood renewable power generation and other energy projects at favorable prices.

Effective January 1, 2011, our existing long-term rail transportation contract, at rates significantly below the current market, expired and we anticipate a decrease in transportation-related revenue of approximately $130 million as a result. The decrease in revenue will be mostly offset by lower variable costs incurred to provide the transportation.

We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers. Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional energy projects to serve energy intensive industrial customers.

ENERGY TRADING

Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers’ behalf.

Energy Trading results are discussed below:


	Three Months Ended					Six Months Ended
	June 30					June 30
(in Millions)	2011		2010			2011		2010
Operating Revenues	$	306	$	117		$	628	$	403
Fuel, Purchased Power and Gas		271		142			567		339

Gross Margin		35		(25	)		61		64
Operation and Maintenance		12		15			31		34
Depreciation, Depletion and Amortization		—		1			1		2
Taxes Other Than Income		1		—			2		2

Operating Income (Loss)		22		(41	)		27		26
Other (Income) and Deductions		2		3			4		7
Income Tax Provision (Benefit)		8		(18	)		9		7

Net Income (Loss) Attributable to DTE Energy Company	$	12	$	(26	)	$	14	$	12

Gross margin increased $60 million in the second quarter of 2011 and decreased $3 million for the six months ended June 30, 2011. The overall increase in gross margin for the second quarter was the result of timing-related gains and improved economic performance, principally in our power and gas trading strategies. We experienced timing-related earnings volatility based on market movement related to derivative contracts.

The second quarter increase of $60 million represents a $40 million increase in unrealized margins and a $20 million increase in realized margins. The $40 million increase in unrealized margins is due to $45 million of favorable results, primarily in our power transmission and power full requirements strategies. This was offset by $5 million of unfavorable results, primarily in our gas trading strategy. The $20 million increase in realized margins is due to $38 million of favorable results, primarily in our power and gas trading strategies, offset by $18 million of unfavorable results, primarily in our power transmission and power origination strategies.

The $3 million decrease for the six month period represents a $19 million decrease in unrealized margins and $16 million increase in realized margins. The $19 million decrease in unrealized margins is due to $43 million of unfavorable results, primarily in our power trading, power transmission and gas storage strategies, offset by $24 million of favorable results, primarily in our power full requirements and gas structured strategies. The $16 million increase in realized margins is due to $35 million of favorable results in our power and gas trading strategies, offset by $19 million of unfavorable results, primarily in our power origination and gas structured strategies.

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

The Energy Trading portfolio includes financial instruments, physical commodity contracts and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power transmission and generation capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers’ behalf. Significant portions of the Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives, whereas natural gas inventory, power transmission, pipeline transportation and certain 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.


(in Millions)	Total
MTM at December 31, 2010	$	(44	)

Reclassify to realized upon settlement		19
Changes in fair value recorded to income		37

Amounts recorded to unrealized income		56
Change in fair value recorded in regulatory liabilities		3
Change in collateral held by (for) others		(15	)
Option premiums received and other		(26	)

MTM at June 30, 2011	$	(26	)


										2014
(in Millions)										And		Total Fair
Source of Fair Value	2011			2012			2013			Beyond		Value
Level 1	$	19		$	(23	)	$	12		$	10	$	18
Level 2		(71	)		(34	)		(35	)		3		(137	)
Level 3		45			15			5			—		65

Total MTM before collateral adjustments	$	(7	)	$	(42	)	$	(18	)	$	13	$	(54	)


Collateral adjustments												$	28


Total MTM at June 30, 2011												$	(26	)


	Credit Exposure
	Before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade(1)
A- and Greater	$	190	$	—		$	190
BBB+ and BBB		241		—			241
BBB-		101		—			101

Total Investment Grade		532		—			532

Non-investment grade(2)		3		—			3
Internally Rated — investment grade(3)		118		—			118
Internally Rated — non-investment grade(4)		25		(3	)		22

Total	$	678	$	(3	)	$	675


(1)		This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 30 percent of the total gross credit exposure.

(2)		This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented approximately 1 percent of the total gross credit exposure.

(3)		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 percent of the total gross credit exposure.

(4)		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 percent of the total gross credit exposure.


	Assuming a						Assuming a
	10% Increase in Rates						10% Decrease in Rates
(in Millions)	As of June 30,						As of June 30
Activity	2011			2010			2011			2010		Change in the Fair Value of
Coal Contract	$	4		$	(1	)	$	(2	)	$	1	Commodity contracts
Gas Contracts		(9	)		(8	)		8			8	Commodity contracts
Power Contracts		(11	)		1			10			1	Commodity contracts
Interest Rate Risk		(283	)		(267	)		304			287	Long-term debt
Foreign Currency Exchange Risk		7			2			—			11	Forward contracts
Discount Rates		—			—			—			—	Commodity contracts


					Total Number of		Maximum Dollar
					Shares Purchased		Value that May Yet
	Total Number		Average		as Part of Publicly		Be Purchased Under
	of Shares		Price Paid		Announced Plans		the Plans or
Period	Purchased(1)		Per Share		or Programs		Programs
04/01/11 — 04/30/11		3,839	$	49.13		—		—
05/01/11 — 05/31/11		139,340		51.28		—		—
06/01/11 — 06/30/11		181,721		48.85		—		—

Total		324,900				—		—


(1)		Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program. Also includes shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.


Exhibit
Number		Description
Exhibits filed herewith:

4-269		Supplemental Indenture, dated as of May 15, 2011, to the Amended and Restated Indenture, dated as of April 9, 2001, by and between DTE Energy Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee. (2011 Series C)

31-67		Chief Executive Officer Section 302 Form 10-Q Certification

31-68		Chief Financial Officer Section 302 Form 10-Q Certification

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

Exhibits incorporated herein by reference:

3-1		Amended Bylaws (as amended through May 5, 2011) (Exhibit 3.1 to Form 8-K dated May 10, 2011)

4-270		Supplemental Indenture, dated as of May 15, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-275 to Detroit Edison’s Form 10-Q for the quarter ended June 30, 2011). (2011 Series B)

Exhibits furnished herewith:

32-67		Chief Executive Officer Section 906 Form 10-Q Certification

32-68		Chief Financial Officer Section 906 Form 10-Q Certification


	DTE ENERGY COMPANY (Registrant)
Date: July 28, 2011	/S/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer