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, 2010

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


Michigan (State or other jurisdiction of incorporation or organization)		38-3217752 (I.R.S. Employer Identification No.)

One Energy Plaza, Detroit, Michigan (Address of principal executive offices)		48226-1279 (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, 2010, 168,791,973 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, 2010

TABLE OF CONTENTS


			Page
Definitions			1

Forward-Looking Statements			3

Part I — Financial Information

Item 1. Financial Statements

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			36

Item 3. Quantitative and Qualitative Disclosures About Market Risk			52

Item 4. Controls and Procedures			55

Part II — Other Information

Item 1. Legal Proceedings			56

Item 1A. Risk Factors			56

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers			57

Item 6. Exhibits			58

Signature			59
EX-31.59
EX-31.60
EX-32.59
EX-32.60

Definitions


ASC		Accounting Standards Codification

ASU		Accounting Standards Update

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) 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.

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.

MNRE		Michigan Department of Natural Resources and Environment

MPSC		Michigan Public Service Commission

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

NRC		United States Nuclear Regulatory Commission

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

PSCR		A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power costs.

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


Unconventional Gas		Includes those oil and gas 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

GWh		Gigawatthour of electricity

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. Forward-looking statements 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 resulting in changes in demand, customer conservation and increased thefts of electricity and gas;

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

	•		economic climate and population growth or decline in the geographic areas where we do business;

	•		high levels of uncollectible accounts receivable;

	•		access to capital markets and capital market conditions 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 that include or could include carbon and more stringent mercury emission controls, a renewable portfolio standard, energy efficiency mandates, a carbon tax or cap and trade structure and ash landfill regulations;

	•		nuclear regulations and operations associated with 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 gas shale resources and challenges in estimating gas 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; and

	•		binding arbitration, litigation and related appeals.

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)	2010			2009			2010			2009
Operating Revenues	$	1,792		$	1,688		$	4,245		$	3,943


Operating Expenses
Fuel, purchased power and gas		608			577			1,603			1,537
Operation and maintenance		597			595			1,249			1,186
Depreciation, depletion and amortization		253			240			504			472
Taxes other than income		80			61			162			141
Other asset (gains) and losses, reserves and impairments, net		(2	)		—			(1	)		(3	)

		1,536			1,473			3,517			3,333


Operating Income		256			215			728			610


Other (Income) and Deductions
Interest expense		136			134			276			266
Interest income		(3	)		(3	)		(6	)		(6	)
Other income		(23	)		(22	)		(42	)		(46	)
Other expenses		15			(5	)		23			9

		125			104			251			223


Income Before Income Taxes		131			111			477			387

Income Tax Provision		44			27			160			124


Net Income		87			84			317			263

Less: Net Income Attributable to Noncontrolling Interests		1			1			2			2


Net Income Attributable to DTE Energy Company	$	86		$	83		$	315		$	261


Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	.51		$	.51		$	1.88		$	1.59


Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	.51		$	.51		$	1.88		$	1.59


Weighted Average Common Shares Outstanding
Basic		169			164			167			164
Diluted		169			164			168			164
Dividends Declared per Common Share	$	.53		$	.53		$	1.06		$	1.06

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)


	June 30			December 31
(in Millions)	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	124		$	52
Restricted cash		87			84
Accounts receivable (less allowance for doubtful accounts of $246 and $262, respectively)
Customer		1,219			1,438
Other		95			217
Inventories
Fuel and gas		353			309
Materials and supplies		212			200
Deferred income taxes		151			167
Derivative assets		175			209
Other		165			201

		2,581			2,877


Investments
Nuclear decommissioning trust funds		824			817
Other		428			598

		1,252			1,415


Property
Property, plant and equipment		21,137			20,588
Less accumulated depreciation, depletion and amortization		(8,366	)		(8,157	)

		12,771			12,431


Other Assets
Goodwill		2,024			2,024
Regulatory assets		4,128			4,110
Securitized regulatory assets		802			870
Intangible assets		58			54
Notes receivable		127			113
Derivative assets		108			116
Other		182			185

		7,429			7,472


Total Assets	$	24,033		$	24,195

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)


	June 30			December 31
(in Millions, Except Shares)	2010			2009
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	684		$	723
Accrued interest		114			114
Dividends payable		89			88
Short-term borrowings		—			327
Current portion long-term debt, including capital leases		1,335			671
Derivative liabilities		170			220
Other		539			502

		2,931			2,645


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		5,584			6,237
Securitization bonds		717			793
Trust preferred-linked securities		289			289
Capital lease obligations		43			51

		6,633			7,370


Other Liabilities
Deferred income taxes		2,209			2,096
Regulatory liabilities		1,397			1,337
Asset retirement obligations		1,480			1,420
Unamortized investment tax credit		80			85
Derivative liabilities		145			198
Liabilities from transportation and storage contracts		89			96
Accrued pension liability		700			881
Accrued postretirement liability		1,316			1,287
Nuclear decommissioning		138			136
Other		315			328

		7,869			7,864


Commitments and Contingencies (Notes 7 and 12)

Equity
Common stock, without par value, 400,000,000 shares authorized, 168,791,973 and 165,400,045 shares issued and outstanding, respectively		3,405			3,257
Retained earnings		3,305			3,168
Accumulated other comprehensive loss		(153	)		(147	)

Total DTE Energy Company Equity		6,557			6,278
Noncontrolling interests		43			38

Total Equity		6,600			6,316

Total Liabilities and Equity	$	24,033		$	24,195

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended
	June 30
(in Millions)	2010			2009
Operating Activities
Net income	$	317		$	263
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		504			472
Deferred income taxes		72			88
Other asset (gains), losses and reserves, net		1			3
Changes in assets and liabilities, exclusive of changes shown separately (Note 15)		257			475

Net cash from operating activities		1,151			1,301


Investing Activities
Plant and equipment expenditures — utility		(463	)		(581	)
Plant and equipment expenditures — non-utility		(52	)		(32	)
Proceeds from sale of other assets, net		24			32
Restricted cash for debt redemption		1			17
Proceeds from sale of nuclear decommissioning trust fund assets		128			182
Investment in nuclear decommissioning trust funds		(145	)		(190	)
Consolidation of VIEs		19			—
Other		(4	)		(38	)

Net cash used for investing activities		(492	)		(610	)


Financing Activities
Issuance of long-term debt		—			363
Redemption of long-term debt		(91	)		(355	)
Short-term borrowings, net		(327	)		(543	)
Issuance of common stock		23			18
Dividends on common stock		(176	)		(173	)
Other		(16	)		(45	)

Net cash used for financing activities		(587	)		(735	)


Net Increase (Decrease) in Cash and Cash Equivalents		72			(44	)
Cash and Cash Equivalents at Beginning of Period		52			86

Cash and Cash Equivalents at End of Period	$	124		$	42

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, 2009		165,400	$	3,257	$	3,168		$	(147	)	$	38	$	6,316

Net income		—		—		315			—			2		317
Benefit obligations, net of tax		—		—		—			14			—		14
Dividends declared on common stock		—		—		(178	)		—			—		(178	)
Issuance of common stock		400		23		—			—			—		23
Contribution of common stock to pension plan		2,224		100		—			—			—		100
Net change in unrealized losses on derivatives, net of tax		—		—		—			2			—		2
Net change in unrealized losses on investments, net of tax		—		—		—			(22	)		—		(22	)
Stock-based compensation and other		768		25		—			—			3		28

Balance, June 30, 2010		168,792	$	3,405	$	3,305		$	(153	)	$	43	$	6,600

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


(in Millions)	2010			2009
Net income	$	317		$	263

Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligation, net of taxes of $2 and $3		4			5
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $5 and $-		10			—

		14			5


Net unrealized gains (losses) on derivatives:
Gains (losses) during the period, net of taxes of $1 and $1		1			3
Amounts reclassified to income, net of taxes of $1 and $(1)		1			(1	)

		2			2


Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $(6) and $4		(12	)		9
Amounts reclassified to income, net of taxes of $- and $2		—			3
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $(5) and $-		(10	)		—

		(22	)		12


Foreign currency translation		—			1


Comprehensive income		311			283
Less: Comprehensive income attributable to noncontrolling interests		2			2

Comprehensive income attributable to DTE Energy Company	$	309		$	281

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 electric energy to approximately 2.1 million customers in southeast Michigan;

	•		MichCon, a natural gas utility engaged in the purchase, storage, transmission, gathering, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan; and

	•		Other businesses involved in (1) natural gas pipelines and storage; (2) unconventional gas 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 MNRE.

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

Basis of Presentation

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2009 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 for a fair presentation of such financial statements. 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, 2010.

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

Principles of Consolidation — Variable Interest Entity (VIE)

As discussed in Note 3, effective January 1, 2010, the Company adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. There is no grandfathering of previous consolidation conclusions. As a result, the Company re-evaluated all prior VIE and primary beneficiary determinations. The requirements of ASU 2009-17 were adopted on a prospective basis.

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 segments 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. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, in 2010 began consolidating five entities that were previously accounted for as equity investments. The primary reason for the change in the primary beneficiary conclusion was the determination that the Company’s responsibility for the management and operations of the VIEs afforded the Company the power to direct the significant activities of the VIEs.

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. Under ASU 2009-17, this entity is now a VIE, and continues to be consolidated as the Company is the primary beneficiary.

DTE Energy has interests in various 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.

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, 2010 and December 31, 2009. Amounts at June 30, 2010 for consolidated VIEs that are either (1) assets that can be used only to settle their obligations 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.


	June 30, 2010
							Restricted		December 31,
(in Millions)	Securitization		Other		Total		Amounts		2009
ASSETS
Cash and cash equivalents	$	—	$	33	$	33	$	1	$	7
Restricted cash		77		5		82		82		—
Accounts receivable		46		92		138		51		3
Inventories		—		78		78		4		39
Other current assets		—		7		7		—		—
Property, plant and equipment		—		398		398		—		44
Securitized regulatory assets		802		—		802		802		—
Notes receivable		—		25		25		18		12
Other assets		18		29		47		20		—

	$	943	$	667	$	1,610	$	978	$	105


LIABILITIES
Accounts payable and accrued current liabilities	$	19	$	46	$	65	$	19	$	3
Current portion long-term debt, including capital leases		144		7		151		146		—
Other current liabilities		44		19		63		44		4
Mortgage bonds, notes and other		—		38		38		21		—
Securitization bonds		717		—		717		717		—
Capital lease obligations		—		24		24		—		26
Other long term liabilities		5		101		106		7		10

	$	929	$	235	$	1,164	$	954	$	43

Amounts for non-consolidated VIEs as of June 30, 2010 and December 31, 2009 are as follows:


			Restricted
			Amounts
	June 30,		June 30,		December 31,
(in Millions)	2010		2010		2009
Other investments	$	59	$	—	$	178
Bank loan guarantee		10		—		11
Trust preferred — linked securities		289		—		289

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Intangible Assets

The Company has certain intangible assets relating to emission allowances and non-utility contracts. Emission allowances are charged to fuel expense as the allowances are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $9 million at June 30, 2010 and December 31, 2009. The gross carrying amount and accumulated amortization of contract intangible assets at June 30, 2010 were $70 million and $21 million, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2009 were $64 million and $19 million, respectively.

Income Taxes

The Company’s effective tax rate for the three months ended June 30, 2010 was 34 percent as compared to 24 percent for the three months ended June 30, 2009, and for the six months ended June 30, 2010 was 34 percent as compared to 32 percent for the six months ended June 30, 2009. The 2010 rate is higher than 2009 due primarily to the recognition of tax benefits from the settlement of tax audits in the second quarter of 2009.

The Company had $8 million and $7 million of unrecognized tax benefits at June 30, 2010 and at December 31, 2009, respectively, that, if recognized, would favorably impact its effective tax rate. The Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $2 million within the next twelve months.

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, 2010, the total cash collateral posted, net of cash collateral received, was $60 million. Derivative assets and derivative liabilities are shown net of collateral of $19 million and $65 million, respectively. At June 30, 2010, the Company recorded cash collateral received of $1 million and cash collateral paid of $15 million not related to unrealized derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

Government Grants

Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the basis of the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a reduction of the associated expense in the period in which the expense is incurred.

NOTE 3 — NEW ACCOUNTING PRONOUNCEMENTS

Variable Interest Entity

In June 2009, the FASB issued ASU 2009-17, Amendments to FASB Interpretation 46(R). This standard amends the consolidation guidance that applies to VIEs and affects the overall consolidation analysis under ASC 810-10, Consolidation. The amendments to the consolidation guidance affect all entities and enterprises currently within the scope of ASC 810-10, as well as qualifying special purpose entities that are currently outside the scope of ASC 810-

10. Accordingly, the Company reconsidered its previous ASC 810-10 conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. ASU 2009-17 is effective as of the beginning of the first fiscal year that begins after November 15, 2009. The Company adopted the standard as of January 1, 2010. The adoption of the standard resulted in the consolidation of certain entities within the Power and Industrial Projects segment where the investments in such entities were previously accounted for under the equity method. See Note 1.

Fair Value Measurements and Disclosures

In January 2010, the FASB issued ASU 2010-06, Improving Disclosures about Fair Value Measurements. ASU 2010-06 requires details of transfers in and out of Level 1 and 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. The Company adopted ASU 2010-06 effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward which is effective for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years.

NOTE 4 — FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the six months ended June 30, 2010 and the year ended December 31, 2009. 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, which 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, 2010:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments⁽²⁾			June 30, 2010
Assets:
Cash equivalents	$	21		$	—		$	—		$	—		$	21
Nuclear decommissioning trusts		548			276			—			—			824
Other investments⁽¹⁾		46			54			—			—			100
Derivative assets:
Foreign currency exchange contracts		—			26			—			(20	)		6
Commodity Contracts:
Natural Gas		1,408			174			7			(1,558	)		31
Electricity		—			779			474			(1,017	)		236
Other		24			9			4			(27	)		10

Total derivative assets		1,432			988			485			(2,622	)		283

Total	$	2,047		$	1,318		$	485		$	(2,622	)	$	1,228

Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(24	)	$	—		$	19		$	(5	)
Interest rate contracts		—			(1	)		—			—			(1	)
Commodity Contracts:
Natural Gas		(1,384	)		(351	)		(5	)		1,555			(185	)
Electricity		—			(854	)		(319	)		1,065			(108	)
Other		(28	)		(17	)		—			29			(16	)

Total derivative liabilities		(1,412	)		(1,247	)		(324	)		2,668			(315	)

Total	$	(1,412	)	$	(1,247	)	$	(324	)	$	2,668		$	(315	)

Net Assets as of June 30, 2010	$	635		$	71		$	161		$	46		$	913


Assets:
Current⁽³⁾	$	890		$	778		$	322		$	(1,794	)	$	196
Noncurrent⁽⁴⁾		1,157			540			163			(828	)		1,032

Total Assets	$	2,047		$	1,318		$	485		$	(2,622	)	$	1,228

Liabilities:
Current	$	(858	)	$	(875	)	$	(243	)	$	1,806		$	(170	)
Noncurrent		(554	)		(372	)		(81	)		862			(145	)

Total Liabilities	$	(1,412	)	$	(1,247	)	$	(324	)	$	2,668		$	(315	)

Net Assets as of June 30, 2010	$	635		$	71		$	161		$	46		$	913

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2009:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			December 31, 2009
Assets:
Cash equivalents	$	15		$	—		$	—		$	—		$	15
Nuclear decommissioning trusts and Other Investments(1)		599			325			—			—			924
Derivative assets		1,080			1,207			385			(2,347	)		325

Total	$	1,694		$	1,532		$	385		$	(2,347	)	$	1,264

Liabilities:
Derivative liabilities	$	(1,120	)	$	(1,370	)	$	(361	)	$	2,433		$	(418	)

Total	$	(1,120	)	$	(1,370	)	$	(361	)	$	2,433		$	(418	)

Net Assets at December 31, 2009	$	574		$	162		$	24		$	86		$	846


⁽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 $21 million of cash equivalents that are included in the Consolidated Statements of Financial Position in Cash and Cash Equivalents.

⁽⁴⁾		Includes $100 million 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, 2010 and 2009:


	Three Months Ended June 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Asset balance as of March 31, 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

Asset balance 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	)


	Three Months Ended June 30, 2009
(in Millions)	Natural Gas			Electricity			Other		Total
Asset (Liability) balance as of March 31, 2009	$	(218	)	$	52		$	2	$	(164	)
Changes in fair value recorded in income		(50	)		(4	)		—		(54	)
Purchases, issuances and settlements		34			(3	)		1		32
Transfers in/out of Level 3		(8	)		—			—		(8	)

Asset (Liability) balance as of June 30, 2009	$	(242	)	$	45		$	3	$	(194	)

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, 2009	$	(23	)	$	27		$	—	$	4


	Six Months Ended June 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Asset balance as of December 31, 2009	$	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

Asset balance 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


	Six Months Ended June 30, 2009
(in Millions)	Natural Gas			Electricity			Other			Total
Asset (Liability) balance as of December 31, 2008	$	(183	)	$	(5	)	$	5		$	(183	)
Changes in fair value recorded in income		97			113			—			210
Changes in fair value recorded in regulatory assets/liabilities		—			—			(2	)		(2	)
Changes in fair value recorded in other comprehensive income		4			—			—			4
Purchases, issuances and settlements		(6	)		(58	)		1			(63	)
Transfers in/out of Level 3		(154	)		(5	)		(1	)		(160	)

Asset (Liability) balance as of June 30, 2009	$	(242	)	$	45		$	3		$	(194	)

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, 2009	$	77		$	124		$	—		$	201

Transfers in/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/out of Level 3 are reflected as if they had occurred at the beginning of the period. No significant transfers between Level 1 and 2 occurred in the three and six months ended June 30, 2010. Transfers from Level 2 to Level 3 of $138 million and $83 million reflect inputs related to certain power transactions identified as unobservable due to lack of available broker quotes for the three and six months ended June 30, 2010, respectively. Transfers out of Level 3 in 2009 reflect increased reliance on broker quotes for certain gas transactions.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized as Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through 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 relative to 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 5 for further information on financial and derivative instruments.

June 30, 2010

December 31, 2009

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$8.6 billion

$7.9 billion

$8.3 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 6 for additional information.

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.

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)	2010		2009
Fermi 2	$	794	$	790
Fermi 1		3		3
Low level radioactive waste		27		24

Total	$	824	$	817

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)	2010			2009			2010			2009
Realized gains	$	12		$	3		$	21		$	19
Realized losses		(11	)		(7	)		(19	)		(34	)
Proceeds from sales of securities		69			69			128			182

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the Asset retirement obligation, 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, 2010
Equity securities	$	404	$	115
Debt securities		408		25
Cash and cash equivalents		12		—

	$	824	$	140


As of December 31, 2009
Equity securities	$	420	$	135
Debt securities		388		17
Cash and cash equivalents		9		—

	$	817	$	152

The debt securities at both June 30, 2010 and December 31, 2009 had an average maturity of approximately 5 years. 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.

Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $61 million and $76 million of unrealized losses as Regulatory assets at June 30, 2010 and 2009, 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, impairment charges for unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no impairment charges for the three and six months ended June 30, 2010 and 2009, for Fermi 1.

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, 2010				December 31, 2009
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	103	$	103	$	106	$	106
Equity securities		6		6		11		11

As of June 30, 2010, these securities are comprised primarily of money-market and equity securities. During the six months ended June 30, 2010, no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into earnings for the period. During the six months ended June 30, 2009, $3 million of unrealized losses on available for sale securities were reclassified out of other comprehensive income into earnings for the period. Gains (losses) related to trading securities held at June 30, 2010 and June 30, 2009 were $(2) million and $1 million, respectively.

NOTE 5 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives on the Consolidated Statements of Financial Position at their fair value 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 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 proprietary gas inventory, unconventional gas reserves, power transmission, pipeline transportation and certain storage assets. Derivatives are generally recorded at fair value and shown as Derivative assets or liabilities on the Consolidated Statements of Financial Position.

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, gathers and distributes natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2013. 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 and storage of natural gas. Fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional gas project development and production. The Company uses derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in Accumulated other comprehensive income will be reclassified to earnings as the related production affects earnings through 2010. Management estimates reclassifying an after-tax gain of approximately $1 million to earnings within the next twelve months.

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 emissions 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 wholesale electricity and natural gas physical products and energy financial instruments, and provides risk 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 certain 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 certain 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 2010, the Company estimates reclassifying $3 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, 2010 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to result in material effects on the Company’s financial statements.

Derivative Activities

The Company manages its MTM risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or 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 associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein. Other also

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 represents the fair value of derivative instruments as of June 30, 2010:


(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Commodity Contracts — Natural Gas	$	2	$	—
Interest rate contracts		—		(1	)


Total derivatives designated as hedging instruments:	$	2	$	(1	)


Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	26	$	(24	)

Commodity Contracts:
Natural Gas		1,587		(1,740	)
Electricity		1,253		(1,173	)
Other		37		(45	)


Total derivatives not designated as hedging instruments:	$	2,903	$	(2,982	)


Total derivatives:

Current	$	1,969	$	(1,976	)
Noncurrent		936		(1,007	)

Total derivatives	$	2,905	$	(2,983	)


	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,969		$	936		$	(1,976	)	$	(1,007	)
Counterparty netting		(1,784	)		(819	)		1,784			819
Collateral adjustment		(10	)		(9	)		22			43

Total derivatives as reported	$	175		$	108		$	(170	)	$	(145	)

The following represents the fair value of derivative instruments as of December 31, 2009:


(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Commodity Contracts — Natural Gas	$	2	$	—


Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	24	$	(31	)

Commodity Contracts:
Natural Gas		1,323		(1,552	)
Electricity		1,304		(1,241	)
Other		19		(27	)


Total derivatives not designated as hedging instruments:	$	2,670	$	(2,851	)


Total derivatives:

Current	$	1,860	$	(1,951	)
Noncurrent		812		(900	)

Total derivatives	$	2,672	$	(2,851	)


	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,860		$	812		$	(1,951	)	$	(900	)
Counterparty netting		(1,644	)		(669	)		1,644			669
Collateral adjustment		(7	)		(27	)		87			33

Total derivatives as reported	$	209		$	116		$	(220	)	$	(198	)

The net effect of derivatives designated as cash flow hedging instruments on the Consolidated Statements of Operations is less than $1 million for the three and six months ended June 30, 2010 and 2009.

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2010 and June 30, 2009 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	2010			2009			2010			2009
Foreign currency exchange contracts	Operating Revenue	$	14		$	(17	)	$	3		$	(11	)

Commodity Contracts:
Natural Gas	Operating Revenue		17			126			27			174
Natural Gas	Fuel, purchased power and gas		1			(2	)		(6	)		(2	)
Electricity	Operating Revenue		(22	)		7			49			23
Other	Operating Revenue		1			(2	)		1			3
Other	Operation and maintenance		(1	)		—			(1	)		—

Total		$	10		$	112		$	73		$	187

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position are $4 million and $3 million in losses related to FTRs recognized in Regulatory liabilities for the three and six months ended June 30, 2010.

The following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2010:


Commodity	Number of Units
Natural Gas (MMBtu)		793,224,124
Electricity (MWh)		74,620,286
Foreign Currency Exchange ($ CAD)		303,977,206

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, 2010, 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 $302 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 6 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2010 follows:


(in Millions)
Asset retirement obligations at December 31, 2009	$	1,439
Accretion		47
Liabilities incurred		10
Liabilities settled		(3	)
Consolidation of VIEs		4

Asset retirement obligations at June 30, 2010		1,497
Less amount included in current liabilities		(17	)

	$	1,480

Substantially all of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

NOTE 7 — REGULATORY MATTERS

Energy Optimization (EO) Plans

In March 2009, Detroit Edison and MichCon filed EO Plans with the MPSC as required under 2008 PA 295. The EO Plan applications are designed to help each customer class reduce their electric and gas usage by: (1) building customer awareness of energy efficiency options and (2) offering a diverse set of programs and participation options that result in energy savings for each customer class. In March 2010, Detroit Edison and MichCon filed amended EO Plans with the MPSC. Detroit Edison’s amended EO Plan application proposed the recovery of EO expenditures for the period 2010-2015 of $406 million and further requested approval of surcharges to recover these costs, including a financial incentive mechanism. MichCon’s amended EO Plan proposed the recovery of EO expenditures for the period 2010-2015 of $150 million and further requested approval of surcharges that are designed to recover these costs, including a financial incentive mechanism. The MPSC has approved the amended EO Plans and the surcharge and tariff sheets reflecting the exclusion of the financial incentive mechanism. The disposition of the financial incentive mechanisms is expected to be addressed in the EO reconciliation cases.

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 are less than the amount provided in rates. Accordingly, Detroit Edison has proposed a refund in the amount of approximately $16 million, including appropriate carry charges.

Detroit Edison Regulatory Asset Recovery Surcharge (RARS) Reconciliation

In April 2010, Detroit Edison filed an application with the MPSC for approval of the final reconciliation of its RARS. Detroit Edison has proposed a refund of approximately $26 million, including appropriate carry charges.

Power Supply Cost Recovery 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.

2008 Plan Year - An MPSC order was issued on July 1, 2010 approving a 2008 PSCR under collection amount of $15.6 million and the recovery of this amount as part of the 2009 PSCR reconciliation. In addition, the order approved Detroit Edison’s Pension Equalization Mechanism reconciliation and authorized the Company to refund the $49.9 million over-recovery, plus interest, to customers beginning with the August 2010 billing month.

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


		Net Over-recovery,	PSCR Cost of
PSCR Year	Date Filed	including interest	Power Sold
2009	March 2010	$15.6 million	$1.1 billion

2009 Gas Rate Case Filing

On June 3, 2010, the MPSC issued an order in MichCon’s June 9, 2009 rate case filing. The MPSC approved an annual revenue increase of $119 million. Included in the approved increase in revenues was a return on equity of 11% on an expected permanent capital structure of 50.4% equity and 49.6% debt. The rate order includes a $22 million impact of lower depreciation rates as ordered by the MPSC in March 2010, effective April 1, 2010. Since the final rate relief ordered was less than the Company’s self-implemented rate increase of $170 million effective on January 1, 2010, the MPSC ordered refunds for the period the self-implemented rates were in effect. MichCon has recorded a refund liability of $17 million at June 30, 2010, representing the estimated refund due customers, including interest. The MPSC ordered MichCon to file a refund plan by September 3, 2010.

Other key aspects of the MPSC order include the following:

	•		Continued application of an Uncollectible Expense Tracking Mechanism with two modifications. The base amount was increased prospectively from $37 million to $70 million with an 80/20 percent sharing of the expenses (modified from 90/10) above or below the base amount.

	•		Implementation of a pilot Revenue Decoupling Mechanism, that will require MichCon to recover or refund the change in distribution revenue resulting from the difference in weather-adjusted average sales per customer by rate schedule compared to the base average sales per customer by rate schedule established in the MPSC order for the period July 1, 2010 to June 30, 2011.

	•		Approval of the recovery of previously expensed CTA. In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. The Company incurred CTA

restructuring expense for employee severance, early retirement programs and other costs which include project management and consultant support. In September 2006, the MPSC issued an order approving a settlement agreement that allowed MichCon, commencing in 2006, to defer the incremental CTA and provided for amortization of the CTA deferral over a ten-year period beginning with the year subsequent to the year the CTA was deferred. The September 2006 order did not provide a regulatory recovery mechanism, therefore MichCon expensed CTA incurred during the period 2006 through 2008. The June 3, 2010 MPSC order provided for recovery of the regulatory unamortized balance of CTA. At June 30, 2010, MichCon deferred and recognized in income approximately $32 million ($20 million after-tax) of previously expensed CTA. The non-pension component of CTA of approximately $21 million is included in Regulatory assets. The pension component of CTA of approximately $11 million is included in Regulatory liabilities.

2010 Gas Rate Case Filing

MichCon filed a general rate case on July 27, 2010 based on a fully projected 2011 test year. The filing with the MPSC requested a $51 million increase in revenues that is required to recover higher costs associated with increased investments in net plant, the impact of sales reductions due to customer conservation and the economic conditions in Michigan, lower projected midstream revenues resulting from reduced storage capacity and MichCon’s shift to a lower risk predominantly long-term storage contract portfolio from a higher risk predominantly short-term storage contract portfolio, and increasing operating costs.

Gas Cost Recovery 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
2008-2009	June 2009	$5.4 million	$1.2 billion

2009-2010	June 2010	$5.9 million	$1.0 billion

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 8 — COMMON STOCK

In March 2010, the Company contributed $100 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was contributed over four business days from March 26, 2010 through March 31, 2010 and was valued using the closing market prices of DTE Energy common stock on each of those days in accordance with fair value measurement and accounting requirements.

NOTE 9 — EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options.


	Three Months						Six Months
	Ended June 30						Ended June 30
(in Millions, except per share amounts)	2010			2009			2010		2009
Basic Earnings per Share
Net income attributable to DTE Energy	$	86		$	83		$	315	$	261


Average number of common shares outstanding		169			164			167		164

Weighted average net restricted shares outstanding		1			1			1		1


Dividends declared — common shares	$	89		$	87		$	177	$	173
Dividends declared — net restricted shares		—			—			1		1

Total distributed earnings	$	89		$	87		$	178	$	174

Net income less distributed earnings	$	(3	)	$	(4	)	$	137	$	87


Distributed (dividends per common share)	$	.53		$	.53		$	1.06	$	1.06
Undistributed		(.02	)		(.02	)		.82		.53

Total Basic Earnings per Common Share	$	.51		$	.51		$	1.88	$	1.59


Diluted Earnings per Share
Net income attributable to DTE Energy	$	86		$	83		$	315	$	261


Average number of common shares outstanding		169			164			167		164
Average incremental shares from assumed exercise of options		—			—			1		—

Common shares for dilutive calculation		169			164			168		164


Weighted average net restricted shares outstanding		1			1			1		1


Dividends declared — common shares	$	89		$	87		$	177	$	173
Dividends declared — net restricted shares		—			—			1		1

Total distributed earnings	$	89		$	87		$	178	$	174

Net income less distributed earnings	$	(3	)	$	(4	)	$	137	$	87


Distributed (dividends per common share)	$	.53		$	.53		$	1.06	$	1.06
Undistributed		(.02	)		(.02	)		.82		.53

Total Diluted Earnings per Common Share	$	.51		$	.51		$	1.88	$	1.59

Options to purchase approximately 0.4 million and 5 million shares of common stock as of June 30, 2010 and 2009, respectively, 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 10 — LONG-TERM DEBT

In March 2010, Detroit Edison agreed to issue and sell $300 million of 4.89%, 10-year Senior Notes to a group of institutional investors in a private placement transaction. The notes are expected to close and fund in September 2010 with proceeds used to repay a portion of Detroit Edison’s 6.125% Senior Notes due October 2010.

NOTE 11 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year and two-year revolving credit facilities are with a syndicate of 22 banks and 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 8.5% 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, as defined in the agreements, of no more than 0.65 to 1. At June 30, 2010, the debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon are 0.50 to 1, 0.51 to 1 and 0.47 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at June 30, 2010 is shown in the following table:


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Five-year unsecured revolving facility, expiring October 2010	$	675	$	69	$	181	$	925
Two-year unsecured revolving facility, expiring April 2011		538		212		250		1,000
Two-year unsecured letter of credit facility, expiring in April 2011		50		—		—		50
Three-year unsecured letter of credit facility, expiring in May 2013		50		—		—		50

Total credit facilities at June 30, 2010	$	1,313	$	281	$	431	$	2,025


Amounts outstanding at June 30, 2010:

Letters of credit		195		—		—		195

		195		—		—		195

Net availability at June 30, 2010	$	1,118	$	281	$	431	$	1,830

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $18 million which are used for various corporate purposes.

In July 2010, the Company entered into a new $125 million five-year unsecured letter of credit facility. This agreement also contains the same total funded debt to capitalization ratio as described above.

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 $120 million with its clearing agent. In April 2010, the agreement was amended to allow 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, 2010, a $10 million letter of credit was in place, raising capacity under this facility for up to $130 million. The $10 million letter of credit is included in the table above. The amount outstanding under this agreement was $84 million and $1 million at June 30, 2010 and December 31, 2009, respectively.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to 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 2009. The Company estimates Detroit Edison will make future undiscounted capital expenditures of up to $73 million in 2010 and up to $2.2 billion of additional capital expenditures through 2019 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. It is not possible to quantify the impact of those 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 Title V 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. The Company believes that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of the Company’s discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. The Company could also be required to install additional pollution control equipment at some or all of the power plants in question, consider early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

Water — In response to an EPA regulation, 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 $55 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 EPA’s use of this provision in determining best technology available for reducing environmental impacts. Concurrently, the EPA continues to develop a revised rule, a draft of which is expected to be published by the end of 2010, with a final rule scheduled for 2012. The EPA has also proposed an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.

Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (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, 2010 and December 31, 2009, the Company had $9 million accrued for remediation.

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 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.

Gas Utility

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. Gas Utility owns, or previously owned, 15 such 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. During 2009, the Company spent approximately

$1 million investigating and remediating these former MGP sites. As of June 30, 2010 and December 31, 2009, the Company had $35 million 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. However, the Company anticipates the cost deferral and rate recovery mechanism approved by the MPSC 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 resulting in the issuance of a notice of violation in June of 2007 regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Company is 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 impact of this settlement. The Company is investigating wastewater treatment technology upgrades such as a biological treatment for the coke battery facility located in Pennsylvania. This investigation may result in capital expenditures of approximately $5 million to $6 million being incurred over the next two years to meet future regulatory requirements. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Other

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 $28 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, 2010, 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 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. The Company has begun work on 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. Below are the details of specific material guarantees the Company currently provides.

Millennium Pipeline Project Guarantee

The Company owns a 26 percent equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium began commercial operations in December 2008. On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010 and was fully drawn as of June 30, 2010. Millennium is refinancing its $800 million borrowing facility with a $725 million long-term financing that will be non-recourse to the Company and is expected to close in August 2010. The Company expects to make an additional equity contribution to Millennium in conjunction with the closing of the long-term financing and repayment of the $800 million borrowing facility. The actual amount of the Company’s equity contribution will depend on the amount of the net proceeds from the long-term financing.

The Company has agreed to guarantee 26 percent of the existing $800 million borrowing facility and in the event of default by Millennium the maximum potential amount of future payments under this guarantee is approximately $210 million. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. Related to this facility, the Company has also agreed to guarantee 26 percent of Millennium’s forward-starting interest rate swaps with a notional amount of $420 million. The Company’s exposure on the forward-starting interest rate swaps varies with changes in swap rates and credit swap spreads and was approximately $26

million at June 30, 2010. On July 20, 2010, the forward-starting swaps were terminated with delayed settlement in August 2010 to coincide with the funding of Millennium’s long-term financing. The Company’s exposure through the settlement date is approximately $27 million. There are no recourse provisions or collateral that would enable the Company to recover any amounts paid under the guarantees, other than its share of project assets.

Other Guarantees

Detroit Edison has guaranteed a bank term loan of $10 million related to the sale of its steam heating business to Thermal Ventures II, L.P. At June 30, 2010, the Company has reserves for the entire amount of the bank loan guarantee.

The Company’s other guarantees are not individually material with maximum potential payments totaling $10 million at June 30, 2010.

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, 2010, the Company had approximately $13 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 July 2010, a new three-year agreement was ratified covering approximately 3,800 represented employees. The majority of its remaining represented employees are under contracts that expire in June 2011 and August 2012.

Purchase Commitments

As of June 30, 2010, 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 2010 through 2051. The Company also estimates that 2010 capital expenditures will be approximately $1.3 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 5 and 7 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 13 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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


							Other Postretirement
(in Millions)	Pension Benefits						Benefits
Three Months Ended June 30	2010			2009			2010			2009
Service cost	$	16		$	13		$	14		$	14
Interest cost		51			51			31			33
Expected return on plan assets		(65	)		(64	)		(18	)		(14	)
Amortization of:
Net actuarial loss		25			13			13			19
Prior service cost		1			2			(1	)		(2	)
Net transition liability		—			—			1			—

Net periodic benefit cost	$	28		$	15		$	40		$	50


							Other Postretirement
(in Millions)	Pension Benefits						Benefits
Six Months Ended June 30	2010			2009			2010			2009
Service cost	$	32		$	26		$	30		$	29
Interest cost		101			101			63			67
Expected return on plan assets		(129	)		(127	)		(37	)		(28	)
Amortization of:
Net actuarial loss		50			26			27			36
Prior service cost		2			3			(2	)		(3	)
Net transition liability		—			—			1			1

Net periodic benefit cost	$	56		$	29		$	82		$	102

Pension and other Postretirement Contributions

The Company contributed $200 million to its pension plans during the first quarter of 2010, including a contribution of DTE Energy stock of $100 million (consisting of approximately 2.2 million shares valued at an average price of $44.97 per share).

The Company expects to contribute $150 million to its postretirement medical and life insurance benefit plans during 2010. During the 2010 second quarter, the Company contributed $25 million to the plans.

Healthcare Legislation

In March 2010, the Patient Protection and Affordable Care Act (PPACA) and the Health Care and Education Reconciliation Act (HCERA) were enacted into law (collectively, the “Act”). The Act is a comprehensive health care reform bill. A provision of the PPACA repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012.

DTE Energy’s retiree healthcare plan includes the provision of postretirement prescription drug coverage (“coverage”) which is included in the calculation of the recorded other postemployment benefit (OPEB) obligation. Because the Company’s coverage meets certain criteria, DTE Energy is eligible to receive the Medicare Part D subsidy. With the enactment of the Act, the subsidy will continue to not be subject to tax, but an equal amount of prescription drug coverage expenditures will not be deductible. Income tax accounting rules require the impact of a change in tax law be recognized in continuing operations in the Consolidated Statements of Operations in the period that the tax law change is enacted.

For DTE Energy and its utilities this change in tax law required a remeasurement of the Deferred Tax Asset related to the OPEB obligation and the Deferred Tax Liability related to the OPEB Regulatory Asset. The net impact of the remeasurement is $23 million, $18 million and $4 million for DTE Energy, Detroit Edison and MichCon, respectively. The Detroit Edison and MichCon amounts have been deferred as Regulatory Assets as the traditional rate setting process allows for the recovery of income tax costs. Income tax expense of $1 million is being recognized related to Corporate entities in the six months ended June 30, 2010.

NOTE 14 — STOCK-BASED COMPENSATION

The Company recorded stock-based compensation expense of $13 million and $12 million, with an associated tax benefit of $5 million and $5 million for the three months ended June 30, 2010 and 2009, respectively. The Company recorded stock-based compensation expense of $29 million and $13 million, with an associated tax benefit of $11 million and $5 million for the six months ended June 30, 2010 and 2009, respectively. Stock-based compensation cost capitalized in property, plant and equipment was $0.8 million and $0.7 million during the three months ended June 30, 2010 and 2009, respectively. Stock-based compensation cost capitalized in property, plant and equipment was $1.8 million and $0.8 million during the six months ended June 30, 2010 and 2009, respectively.

Stock Options

The following table summarizes the Company’s stock option activity for the six months ended June 30, 2010:


						(in Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Options outstanding at December 31, 2009		5,593,392		$	40.50
Granted		611,500		$	43.95
Exercised		(858,022	)	$	39.35
Forfeited or expired		(106,316	)	$	42.33

Options outstanding at June 30, 2010		5,240,554		$	41.05	$	29.1

Options exercisable at June 30, 2010		3,849,062		$	42.37	$	16.4

As of June 30, 2010, the weighted average remaining contractual life for the exercisable shares was 4.49 years. As of June 30, 2010, 1,391,492 options were non-vested. During the six months ended June 30, 2010, 663,220 options vested.

The weighted average grant date fair value of options granted during the six months ended June 30, 2010 was $5.62 per share. The intrinsic value of options exercised for the six months ended June 30, 2010 was $6 million. Total option expense recognized was $2 million and $2 million for the six months ended June 30, 2010 and 2009, respectively.

The Company determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:


	Six Months Ended
	June 30, 2010			June 30, 2009
Risk-free interest rate		2.91	%		2.04	%
Dividend yield		5.08	%		4.98	%
Expected volatility		22.96	%		27.88	%
Expected life	6 years			6 years

Restricted Stock Awards

The following summarizes stock awards activity for the six months ended June 30, 2010:


				Weighted Average
	Restricted			Grant Date
	Stock			Fair Value
Balance at December 31, 2009		1,024,765		$	37.11
Grants		230,655			44.00
Forfeitures		(15,320	)		36.81
Vested and issued		(370,064	)		37.13

Balance at June 30, 2010		870,036			38.93

Performance Share Awards

The following summarizes performance share activity for the six months ended June 30, 2010:


	Performance Shares
Balance at December 31, 2009		1,455,042
Grants		566,401
Forfeitures		(44,639	)
Payouts		(406,821	)

Balance at June 30, 2010		1,569,983

Unrecognized Compensation Cost

As of June 30, 2010, the Company had $61 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 1.86 years.

NOTE 15 — SUPPLEMENTAL CASH FLOW INFORMATION

The following provides detail of 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)	2010			2009
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	260		$	488
Accrued GCR revenue		(3	)		17
Inventories		(34	)		78
Accrued/prepaid pensions		(99	)		(73	)
Accounts payable		7			(203	)
Accrued PSCR refund		(23	)		82
Income taxes payable		40			54
Derivative assets and liabilities		(62	)		(90	)
Gas inventory equalization		68			96
Postretirement obligation		17			(21	)
Other assets		107			143
Other liabilities		(21	)		(96	)

	$	257		$	475


Noncash financing activities:
Common stock issued for employee benefit plans	$	136		$	21

NOTE 16 — SEGMENT INFORMATION

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

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

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

Gas Storage and Pipelines consists of natural gas pipelines and storage businesses.

Unconventional Gas Production is engaged in unconventional gas 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, power generation and coal transportation and marketing.

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 Michigan Business Tax 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. 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)	2010			2009			2010			2009
Electric Utility	$	9		$	8		$	15		$	14
Gas Utility		(1	)		(1	)		—			—
Gas Storage and Pipelines		1			1			2			3
Power and Industrial Projects		70			(7	)		72			(3	)
Energy Trading		18			21			44			53
Corporate & Other		(12	)		(16	)		(33	)		(39	)

	$	85		$	6		$	100		$	28

Financial data of the business segments follows:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2010			2009			2010			2009
Operating Revenues
Electric Utility	$	1,208		$	1,108		$	2,354		$	2,226
Gas Utility		232			292			987			1,063
Gas Storage and Pipelines		21			20			42			42
Unconventional Gas Production		8			8			16			15
Power and Industrial Projects		291			138			543			293
Energy Trading		117			128			403			332
Corporate & Other		—			—			—			—
Reconciliation & Eliminations		(85	)		(6	)		(100	)		(28	)

Total	$	1,792		$	1,688		$	4,245		$	3,943


Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	87		$	79		$	178		$	157
Gas Utility		19			(15	)		98			46
Gas Storage and Pipelines		10			10			24			24
Unconventional Gas Production		(2	)		(2	)		(5	)		(4	)
Power and Industrial Projects		22			(6	)		40			(2	)
Energy Trading		(26	)		27			12			67
Corporate & Other		(24	)		(10	)		(32	)		(27	)

Net Income Attributable to DTE Energy	$	86		$	83		$	315		$	261

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 2010 was $86 million, or $0.51 per diluted share, compared to net income attributable to DTE Energy of $83 million, or $0.51 per diluted share, in the second quarter of 2009. Net income attributable to DTE Energy in the six months ended June 30, 2010 was $315 million, or $1.88 per diluted share, compared to net income attributable to DTE Energy of $261 million, or $1.59 per diluted share, in the comparable period of 2009. The increases in net income are primarily due to higher earnings in the electric and gas utilities and in the Power and Industrial Projects segment, partially offset by lower earnings in Energy Trading.

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

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

Impact of Economic Conditions

Beginning in the 2010 second quarter, Detroit Edison has experienced increases in residential, industrial and interconnection sales. Commercial sales continue to be lower due primarily to customers participating in the electric Customer Choice program. The residential and industrial sales increases are a result of a slight improvement in economic conditions, particularly in the automotive and steel industries and their related suppliers and other ancillary businesses. The impact of customers participating in the electric Customer Choice program is mitigated by the Customer Incentive Mechanism (CIM). The CIM is an over/under recovery mechanism which measures non-fuel revenues that are lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceed the baseline amount from Detroit Edison’s most recent rate case, 90% of its lost non-fuel revenues associated with sales above that level may be recovered from bundled customers. If annual electric Customer Choice sales decrease below the baseline, the company must refund 100% of its increase in non-fuel revenues associated with sales below that level to bundled customers.

MichCon’s revenues were lower due primarily to lower natural gas costs, a decrease in the number of customers in our service territory, and reduced natural gas usage by customers due to economic conditions in its service territory and an increased emphasis on conservation of energy usage. MichCon’s revenues include a component for the cost of natural gas sold that is recoverable through the Gas Cost Recovery (GCR) mechanism. As the cost of natural gas increases or decreases, the corresponding revenues collected under the GCR mechanism are also higher or lower.

We expect to minimize the impacts of declines in average customer usage through regulatory mechanisms which decouple our revenue levels from sales volumes. The January 2010 MPSC order in Detroit Edison’s 2009 rate case provided for, among other items, the implementation of a pilot electric Revenue Decoupling Mechanism (RDM) effective February 1, 2010. The electric RDM enables Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The June 2010 MPSC order in MichCon’s 2009 rate case provided for, among other items, the implementation of a pilot gas RDM effective July 1, 2010. The gas RDM enables MichCon to recover or refund the change in distribution revenue resulting from the difference in weather-adjusted average sales per customer by rate schedule compared to the base average sales per customer by rate schedule established in the MPSC order. The RDMs for Detroit Edison and MichCon address changes in customer usage due to general economic conditions and conservation, but do not shield the utilities from the impacts of lost customers. In addition, the pilot electric RDM shields Detroit Edison from the impact of weather on customer usage. The pilot gas RDM does not shield MichCon from the impact of weather on customer usage. The electric and gas RDMs are subject to review by the MPSC after the initial one-year pilot programs.

We have been impacted by the timing and level of recovery in the national and regional economies. As discussed further below, economic conditions impact our ability to collect amounts due from our electric and gas customers and drive increased thefts of electricity and natural gas. In the face of these economic conditions, we are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects. We 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.

Collectibility of Accounts Receivable on Utility Operations

Both utilities continue to experience high levels of past due receivables primarily attributable to economic conditions. Our service territories continue to experience high levels of unemployment, underemployment and low income households, home foreclosures and a lack of adequate levels of assistance for low-income customers. Despite the economic conditions, total arrears were reduced during 2010 in our electric and gas utilities. We have taken actions to manage the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers. Detroit Edison has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense for each year and the $66 million level reflected in base rates. In the June 2010 MPSC rate order, the base amount of MichCon’s uncollectible expense tracking mechanism was increased prospectively from $37 million to $70 million and MichCon’s portion of recovery or refund of the expenses above or below the base amount was modified to 80 percent from 90 percent. The Detroit Edison and MichCon uncollectible tracking mechanisms require annual reconciliation proceedings before the MPSC.

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. 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. Our Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. In addition, Millennium Pipeline is well positioned for growth related to 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 exploration, development and production within the Barnett shale in north Texas. We continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. Due to economic conditions and low natural gas prices, we expect drilling activity in 2010 to remain consistent with 2009 levels. We also continue to evaluate leasing opportunities in active development areas in the Barnett shale to optimize our existing portfolio.

Power and Industrial Projects is comprised primarily of projects that deliver energy and products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity 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. The increasing number of states with renewable portfolio standards and energy efficiency mandates provides the opportunity to market the expertise of the Power and Industrial Projects segment in landfill gas, on-site energy management, waste-wood power generation, 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 which may include the management of associated storage and transportation contracts on the customers’ behalf.

CAPITAL INVESTMENTS

We anticipate significant capital investments during the next three years concentrated primarily in Detroit Edison. 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, Detroit Edison’s investments (excluding investments in new base-load generation capacity, if any) will be driven by renewable investment and environmental controls expenditures. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

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. See Note 2 of the Notes to Consolidated Financial Statements.

Non-utility investments are expected primarily in continued investment 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.

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, 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. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. It is not possible to quantify the impact of those expected rulemakings at this time.

of Significant Deterioration requirements, and Title V 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. We believe that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. The Company could also be required to install additional pollution control equipment at some or all of the power plants in question, consider early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

Water — In response to an EPA regulation, 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 perform some mitigation activities, including the possible installation of additional control technologies to reduce the environmental impact of the intake structures. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation, resulting in a delay in complying with the regulation. In 2008, the U.S. Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld EPA’s use of this provision in determining best available technology for reducing environmental impacts. Concurrently, the EPA continues to develop a revised rule, a draft of which is expected to be published by the end of 2010, with a final rule scheduled for 2012. The EPA has also proposed an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.

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 for heating and other uses, have been designated as MGP sites. Gas Utility owns, or previously owned, fifteen 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. EPA is currently considering either, to designate coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. However, agencies and legislatures have urged EPA to regulate coal ash as a non-hazardous waste. If 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.

Global Climate Change

Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs to emit greenhouse gases. Despite action by the Senate Environmental and Public Works Committee to pass a similar but more stringent bill in October 2009 and the release of the American Power Act discussion draft by Senators Kerry and Lieberman in 2010, full Senate action on a climate bill is unlikely in 2010. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures and the purchase of emission allowances from market sources. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced

from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify these impacts on DTE Energy or its customers at this time.

OUTLOOK

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

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

	•		improving Electric and Gas Utility customer satisfaction;

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

	•		managing the growth of our utility asset base;

	•		enhancing 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 if we can secure opportunities that meet our strategic, financial and risk criteria.

RESULTS OF OPERATIONS

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

Net income attributable to DTE Energy by segment for the three and six months ended June 30, 2010 and 2009 is as follows:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2010			2009			2010			2009
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	87		$	79		$	178		$	157
Gas Utility		19			(15	)		98			46
Gas Storage and Pipelines		10			10			24			24
Unconventional Gas Production		(2	)		(2	)		(5	)		(4	)
Power and Industrial Projects		22			(6	)		40			(2	)
Energy Trading		(26	)		27			12			67
Corporate & Other		(24	)		(10	)		(32	)		(27	)

Net Income Attributable to DTE Energy	$	86		$	83		$	315		$	261

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Electric Utility results are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2010			2009			2010			2009
Operating Revenues	$	1,208		$	1,108		$	2,354		$	2,226
Fuel and Purchased Power		390			372			733			712

Gross Margin		818			736			1,621			1,514
Operation and Maintenance		326			306			635			622
Depreciation and Amortization		210			197			414			385
Taxes Other Than Income		61			44			126			104
Other Asset (Gains) and Losses, Net		—			—			(1	)		—

Operating Income		221			189			447			403
Other (Income) and Deductions		79			61			158			145
Income Tax Provision		55			49			111			101

Net Income Attributable to DTE Energy Company	$	87		$	79		$	178		$	157

Operating Income as a Percentage of Operating Revenues		18	%		17	%		19	%		18	%

Gross margin increased $82 million in the second quarter of 2010 and $107 million in the six-month period ended June 30, 2010. The following table details changes in various gross margin components relative to the comparable prior period:


(in Millions)	Three Months			Six Months
January 2010 rate order	$	52		$	104
Restoration tracker		7			(3	)
Securitization bond and tax surcharge rate increase		4			17
Regulatory Asset Revenue surcharge		(10	)		(21	)
Other		29			10

Increase in gross margin	$	82		$	107

Three Months Ended

Six Months Ended

June 30

(in Thousands of MWh)

2010

2009

2010

2009

Electric Sales

Residential

3,602

3,147

7,267

6,885

Commercial

3,988

4,536

7,930

8,959

Industrial

2,605

2,385

5,081

5,022

Other

799

782

1,600

1,599

10,994

10,850

21,878

22,465

Interconnections sales (1)

1,450

1,189

2,760

2,224

Total Electric Sales

12,444

12,039

24,638

24,689

Electric Deliveries

Retail and Wholesale

10,994

10,850

21,878

22,465

Electric Customer Choice, including self generators (2)

1,283

344

2,386

661

Total Electric Sales and Deliveries

12,277

11,194

24,264

23,126


(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)	2010			2009			2010			2009
Power Plant Generation
Fossil		9,595			9,852			19,115			19,694
Nuclear		2,087			1,486			4,287			3,740

		11,682			11,338			23,402			23,434
Purchased Power		1,474			1,464			2,796			2,816

System Output		13,156			12,802			26,198			26,250
Less Line Loss and Internal Use		(712	)		(763	)		(1,560	)		(1,561	)

Net System Output		12,444			12,039			24,638			24,689


Average Unit Cost ($/MWh)
Generation (1)	$	18.96		$	18.97		$	18.87		$	18.10

Purchased Power	$	45.60		$	41.83		$	39.31		$	38.05

Overall Average Unit Cost	$	21.95		$	21.58		$	21.05		$	20.24


(1)		Represents fuel costs associated with power plants.

Operation and maintenance expense increased $20 million in the second quarter of 2010 and $13 million in the six-month period ended June 30, 2010. The increase for the second quarter is primarily due to higher storm expenses of $13 million, higher energy optimization and renewable energy expenses of $7 million, higher maintenance expenses of $5 million, higher employee benefit-related expenses of $4 million and higher other expenses of $10 million, partially offset by reduced uncollectible expenses of $19 million. The increase for the six-month period is primarily due to higher storm and line clearance expenses of $13 million, higher energy optimization and renewable energy expenses of $13 million, higher employee benefit-related expenses of $8 million, partially offset by reduced uncollectible expenses of $19 million.

Taxes other than income were higher by $17 million in the 2010 second quarter and $22 million in the 2010 six-month period due primarily to a $13 million reduction in property tax expense in 2009 due to refunds received in partial settlement of appeals of assessments for prior years.

Outlook —To address the impacts of economic conditions, we continue to move forward in our efforts to improve the operating performance and cash flow of Detroit Edison. The January 2010 MPSC order provided for an uncollectible expense tracking mechanism and a revenue decoupling mechanism which assists in mitigating the impacts of economic conditions in our service territory. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, we face additional issues, such as higher levels of capital spending, volatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue an intense focus on our continuous improvement efforts to improve productivity and decrease our costs while improving customer satisfaction.

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)	2010			2009			2010			2009
Operating Revenues	$	232		$	292		$	987		$	1,063
Cost of Gas		83			138			547			651

Gross Margin		149			154			440			412
Operation and Maintenance		69			123			178			242
Depreciation and Amortization		22			27			48			53
Taxes Other Than Income		14			12			31			26
Other Asset Losses and Reserves, Net		—			(1	)		—			(1	)

Operating Income (Loss)		44			(7	)		183			92
Other (Income) and Deductions		14			15			30			28
Income Tax Provision		11			(7	)		55			18

Net Income (Loss) Attributable to DTE Energy Company	$	19		$	(15	)	$	98		$	46


Operating Income as a Percentage of Operating Revenues		19	%		(2	)%		19	%		9	%

Gross margin decreased $5 million in the second quarter of 2010 and increased $28 million in the six-month period ended June 30, 2010. The following table details changes in various gross margin components relative to the comparable prior period:


(in Millions)	Three Months			Six Months
January 1, 2010 self-implementation and June 2010 rate order	$	20		$	82
Weather		(12	)		(29	)
Uncollectible tracking mechanism		(17	)		(22	)
Other		4			(3	)

Increase (decrease) in gross margin	$	(5	)	$	28


	Three Months Ended				Six Months Ended
	June 30				June 30
(in Millions)	2010		2009		2010		2009
Gas Markets
Gas sales	$	153	$	219	$	791	$	892
End user transportation		33		26		106		78

		186		245		897		970
Intermediate transportation		16		17		31		34
Storage and other		30		30		59		59

	$	232	$	292	$	987	$	1,063


Gas Markets (in Bcf)
Gas sales		14		18		71		86
End user transportation		28		21		72		63

		42		39		143		149
Intermediate transportation		108		123		207		267

		150		162		350		416

Operation and maintenance expense decreased $54 million in the second quarter of 2010 and $64 million in the six-month period ended June 30, 2010. The decreases for the 2010 three-month and six-month periods are due to the deferral of $32 million of previously expensed CTA restructuring expenses and reduced uncollectible expenses of $25 million and $32 million, respectively, for the three-month and six-month periods. See Note 7 of Notes to Consolidated Financial Statements.

Depreciation and amortization expense decreased $5 million in the 2010 three-month and six-month periods due to the March 2010 MPSC order that reduced MichCon’s depreciation rates effective April 1, 2010.

Outlook — To address the impacts of economic conditions, we continue to move forward in our efforts to improve the operating performance and cash flow of Gas Utility. Economic conditions have resulted in a decrease in the number of customers in our service territory, customer conservation and continued high levels of theft and uncollectible accounts receivable. The uncollectible tracking mechanism provided by the MPSC assists in mitigating the continued pressure on accounts receivable. The June 2010 MPSC order provided for a revenue decoupling mechanism which assists in mitigating the impacts of economic conditions in our service territory. We continue to resolve outstanding regulatory issues. Looking forward, we face additional issues, such as higher capital spending related to renewal of our gas distribution infrastructure, volatility in gas prices, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue an intense focus on our continuous improvement efforts to improve productivity, minimize lost and stolen gas and decrease our costs while improving customer satisfaction.

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 were consistent with those of the prior periods and are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2010			2009			2010			2009
Operating Revenues	$	21		$	20		$	42		$	42
Operation and Maintenance		4			4			8			7
Depreciation and Amortization		2			1			3			2
Taxes Other Than Income		1			1			1			2

Operating Income		14			14			30			31
Other (Income) and Deductions		(2	)		(4	)		(10	)		(11	)
Income Tax Provision		6			7			15			17

Net Income		10			11			25			25
Noncontrolling Interest		—			1			1			1

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

Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan. In late 2009, Vector’s expansion went into service, bringing Vector’s total long-haul capacity to nearly 1.3 Bcf/d. In the future, the focus of our growth will be related to our Millennium Pipeline position and will be based upon the growth of the Northeast markets and the increased production expected from the Marcellus Shale in Northern Pennsylvania and Southern New York. We are a 50 percent owner in the proposed Dawn Gateway Pipeline. The Dawn Gateway Pipeline received all of the necessary approvals in Canada in the first quarter of 2010 but due to changing market conditions, the pipeline joint venture has agreed with its customers’ request to delay the planned 2010 construction for up to two years.

UNCONVENTIONAL GAS PRODUCTION

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

Unconventional Gas Production results were consistent with those of the prior period.

Unconventional Gas Production results are discussed below:


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2010			2009			2010			2009
Operating Revenues	$	8		$	8		$	16		$	15
Operation and Maintenance		4			3			8			7
Depreciation, Depletion and Amortization		4			4			8			9
Taxes Other Than Income		1			1			1			1
Other Asset (Gains) and Losses, Net		—			1			4			1

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

Net Income (Loss) Attributable to DTE Energy Company	$	(2	)	$	(2	)	$	(5	)	$	(4	)

Other Asset (Gains) and Losses, Net increased $3 million in the six-month period ended June 30, 2010 due to higher impairments of expired or expiring leasehold positions that the Company does not intend to drill at current commodity prices.

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 within our asset base, when conditions are appropriate. Our strategy for 2010 is to maintain our focus on reducing operating expenses and optimizing production volume. During 2010, we expect to invest approximately $25 million to drill 10 to 15 new wells, continue to acquire select acreage and achieve production of approximately 5 Bcfe of natural gas, compared with 5 Bcfe in 2009.

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 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)	2010			2009			2010			2009
Operating Revenues	$	291		$	138		$	543		$	293
Operation and Maintenance		250			140			464			281
Depreciation and Amortization		14			10			29			20
Taxes Other Than Income		3			2			7			6
Other Asset (Gains) Losses and Reserves and Impairments, Net		(2	)		(1	)		(4	)		(4	)

Operating Income (Loss)		26			(13	)		47			(10	)
Other (Income) and Deductions		2			3			5			5
Income Taxes
Provision (Benefit)		10			(6	)		17			(7	)
Production Tax Credits		(9	)		(4	)		(16	)		(7	)

		1			(10	)		1			(14	)

Net Income (Loss)		23			(6	)		41			(1	)
Noncontrolling Interests		1			—			1			1

Net Income (Loss) Attributable to DTE Energy Company	$	22		$	(6	)	$	40		$	(2	)

VIEs — As discussed in Note 3 of Notes to the Consolidated Financial Statements, effective January 1, 2010, we adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, began consolidating five entities. Since these entities were previously accounted for under the equity method, the VIE consolidation had no impact on Net Income Attributable to DTE Energy. As a result of the consolidation of these VIEs, Operating Revenues and Operations and Maintenance expense increased $46 million and $26 million, respectively, for the second quarter of 2010, and $92 million and $62 million, respectively, for the six-month period ended June 30, 2010.

Operating revenues increased $107 million and $158 million, net of VIE adjustments, in the second quarter and six-month period ended June 30, 2010 compared to the same periods in 2009. The increase in the second quarter of 2010 is attributed primarily to $65 million of higher coke demand, a $38 million increase in on-site services, and a $4 million increase in coal transportation services. The increase in the six-month period is attributed primarily to $106 million of higher coke demand, a $60 million increase in on-site services, partially offset by an $8 million decrease in coal transportation services.

Operation and maintenance expense increased $84 million and $121 million, net of VIE adjustments, in the second quarter and six-month period ended June 30, 2010 compared to the same periods in 2009. The increase in the second quarter of 2010 is due primarily to $41 million of higher coke demand, a $39 million increase in on-site services and a $2 million increase in coal transportation services. The increase in the six-month period is due primarily to $62 million of higher coke demand, a $60 million increase in on-site services, partially offset by $10 million of lower coal transportation services.

Outlook — We expect a sustained demand for metallurgical coke and pulverized coal supplied to steel industry customers for 2010. We expect a continued demand for these products in 2011. We supply onsite energy services to the domestic automotive manufacturers who have also experienced stabilized demand for automobiles. Our onsite energy services will continue to be delivered in accordance with the terms of long-term contracts.

In 2010, we will capture benefits from production tax credits up to $30 million generated from our steel industry fuel projects. The tax credits are available through 2010 with the potential of being extended for an additional year. In late 2009, we began operating reduced emission fuel facilities located at Detroit Edison owned coal-fired power plants. The facilities reduce NOx, SOx and mercury emissions and qualify for production tax credits if the fuel is sold to an unrelated party. Therefore, we continue to optimize these facilities by seeking investors for facilities operating at Detroit Edison sites and intend to relocate other facilities to alternative sites which may provide increased production and emission reduction opportunities in 2011.

In 2011, our existing long-term rail transportation contract, which is at rates significantly below the current market, will expire and we anticipate a decrease in annual transportation-related revenue of approximately $120 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. We will also continue to look for opportunities to acquire energy projects and biomass fired generating projects at favorable prices.

ENERGY TRADING

Energy Trading results are discussed below:


	Three Months Ended					Six Months Ended
	June 30					June 30
(in Millions)	2010			2009		2010		2009
Operating Revenues	$	117		$	128	$	403	$	332
Fuel, Purchased Power and Gas		142			74		339		190

Gross Margin		(25	)		54		64		142
Operation and Maintenance		15			17		34		35
Depreciation, Depletion and Amortization		1			2		2		3
Taxes Other Than Income		—			—		2		2

Operating Income (Loss)		(41	)		35		26		102
Other (Income) and Deductions		3			2		7		4
Income Tax Provision		(18	)		6		7		31

Net Income (Loss) Attributable to DTE Energy Company	$	(26	)	$	27	$	12	$	67

Gross margin decreased $79 million in the second quarter of 2010 and decreased $78 million in the six-month period ended June 30, 2010. The overall decrease in gross margin for the second quarter and six-month period ended June 30, 2010 as compared to the same periods in 2009 was the result of increasing gas commodity prices in 2010, coupled with the absence of prior year timing-related gains. We experienced timing-related volatility based on market movement related to derivative contracts. The second quarter 2010 decrease represents a $72 million decrease in unrealized margins and $7 million decrease in realized margins. The $72 million decrease in unrealized margins is due to $78 million of unfavorable results, primarily in our power trading, power transmission and gas transportation strategies, offset by $6 million of favorable results, primarily in our gas full requirements strategy. The $7 million decrease in realized margins is due to $32 million of unfavorable results, primarily in our gas trading strategy, offset by $25 million of favorable results, primarily in our power transmission, power full requirements and power origination strategies.

The decrease for the six-month period represents a $66 million decrease in unrealized margins and $12 million decrease in realized margins. The $66 million decrease in unrealized margins is due to $76 million of unfavorable results, primarily in our gas trading and power full requirements strategies, offset by $10 million of favorable results, primarily in our power trading strategy. The $12 million decrease in realized margins is due to $35 million of unfavorable results, primarily in our power trading and gas transportation strategies, offset by $23 million of favorable results, primarily in our power full requirements, power origination and gas storage strategies.

Income tax provision decreased $24 million in both the second quarter and the six-month period ended June 30, 2010. This decrease is due to a decrease in income taxes attributable to lower pretax income, offset by $7 million of favorable tax-related adjustments resulting from the settlement of federal income tax audits in the second quarter of 2009.

Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The 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 which may include the management of associated storage and transportation contracts on the customers’ behalf. Most financial instruments and physical power and gas contracts are deemed derivatives, whereas proprietary 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.

See also the “Fair Value” section that follows.

CORPORATE & OTHER

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

The net loss for the second quarter of 2010 and six-month period ended June 30, 2010 increased by $14 million and $5 million, respectively. The increases were due primarily to unfavorable effective tax rate adjustments in 2010 and the impact of tax-related adjustments resulting from the recognition of tax benefits from the settlement of tax audits in 2009.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and gas utilities, grow our non-utility businesses, to retire and pay interest on long-term debt and to pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2010, we expect that cash from operations will be lower due to higher tax payments and working capital requirements. We anticipate base level capital investments and expenditures for existing businesses in 2010 of up to $1.3 billion. We expect over $2.2 billion of future environmental capital expenditures through 2019 to satisfy both existing and proposed new requirements. The capital needs of our utilities will also increase due primarily to renewable and energy optimization related expenditures. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.


	Six Months Ended
	June 30
(in Millions)	2010			2009
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	317		$	263
Depreciation, depletion and amortization		504			472
Deferred income taxes		72			88
Other assets (gains), losses and reserves, net		1			3
Working capital and other		257			475

		1,151			1,301


Investing activities:
Plant and equipment expenditures — utility		(463	)		(581	)
Plant and equipment expenditures — non-utility		(52	)		(32	)
Proceeds from sale of other assets, net		24			32
Restricted cash and other investments		(1	)		(29	)

		(492	)		(610	)


Financing activities:
Issuance of long-term debt		—			363
Redemption of long-term debt		(91	)		(355	)
Short-term borrowings, net		(327	)		(543	)
Issuance of common stock		23			18
Dividends on common stock and other		(192	)		(218	)

		(587	)		(735	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	72		$	(44	)

Cash from Operating Activities

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

Cash from operations in the six months ended June 30, 2010 decreased $150 million from the comparable 2009 period primarily due to lower cash provided by working capital items in 2010. See Note 15 of the Notes to Consolidated Financial Statements.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated from plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.

Net cash used for investing activities was lower in the six months ended June 30, 2010 by $118 million primarily due to lower capital expenditures in our utilities.

Cash from Financing Activities

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

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

Net cash used for financing activities decreased $148 million during the six months ended June 30, 2010 due to decreased payments for short-term borrowings.

Outlook

We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and the non-utility businesses. We expect growth in our utilities to be driven primarily by new and existing state and federal regulations that will result in additional environmental and renewable energy investments which will increase the base from which rates are determined. Our non-utility growth is expected from additional investments in energy projects as economic conditions improve.

We continue to be impacted by national and regional economic conditions. We may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.

In July 2010, the Company entered into a new $125 million five-year unsecured letter of credit facility. The agreement requires us to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1.

We have a $925 million five-year unsecured revolving credit facility expiring in October 2010. We are pursuing a replacement for that facility before its expiration. Given current conditions in the credit markets, we anticipate that the terms of the new facility will be substantially similar to our existing $1 billion two-year revolving credit facility that expires in April 2011 with respect to such items as bank participation, allocation levels and covenants. We are also pursuing an extension of that two-year facility. See Note 11 of the Notes to Consolidated Financial Statements.

We have approximately $1.3 billion in long-term debt maturing in the next twelve months. DTE Energy has $600 million of unsecured debt maturing in June 2011 which is expected to be funded through a combination of internally generated funds and the issuance of debt and/or equity. DTE Energy has approximately $1.8 billion of available liquidity at June 30, 2010. In March 2010, Detroit Edison agreed to issue and sell $300 million of 4.89%, 10-year Senior Notes to a group of institutional investors in a private placement transaction. The notes are expected to close and fund in September 2010 with proceeds used to repay a portion of Detroit Edison’s $500 million 6.125% Senior Notes due October 2010. The additional $200 million maturing in October 2010 is expected to be funded through a planned debt issuance later in 2010. Substantially all of the remaining debt maturities relate to Securitization. The principal amount of the Securitization debt is funded through a surcharge payable by Detroit Edison’s electric customers.

In March 2010, the Patient Protection and Affordable Care Act (PPACA) and the Health Care and Education Reconciliation Act (HCERA) were enacted into law (collectively, the “Act”). The Act is a comprehensive health care reform bill. A provision of the PPACA repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012. We are currently assessing other impacts the legislation may have on our healthcare costs. We contributed $200 million to our pension plans during the six months ended June 30, 2010, including a DTE Energy stock contribution of $100 million in March 2010. We expect to contribute $150 million to our postretirement medical and life insurance benefit plans during 2010. We contributed $25 million to our postretirement medical and life insurance benefit plans during the 2010 second quarter. See Note 13 of the Notes to Consolidated Financial Statements.

In July 2010, a federal financial reform act was signed into law. The legislation reshapes financial regulation and is intended to address specific issues that contributed to the financial crisis. Most major areas of the legislation will be dependent upon regulatory interpretation, rulemaking and implementation. We are unable to predict the ultimate outcome of this legislation, but do not expect any material effect on our operations and financial position.

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

CRITICAL ACCOUNTING ESTIMATES

Regulation

A significant portion of our business is subject to regulation. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses.

In March 2010, the Patient Protection and Affordable Care Act (PPACA) and the Health Care and Education Reconciliation Act (HCERA) were enacted into law (collectively, the “Act”). A provision of the PPACA repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012. This change in tax law required a remeasurement of the deferred tax asset related to the Other Postretirement Benefit Obligation (OPEB) and the deferred tax liability related to the OPEB Regulatory Asset. Income tax accounting rules require the impact of a change in tax law be recognized in continuing operations in the Consolidated Statements of Operations in the period that the tax law change is enacted. However, regulated businesses may defer changes in tax law if allowed by regulators. The MPSC’s historical practice has been to recognize both the expense and working capital impacts for OPEB costs. In addition, the current and deferred tax effects related to OPEB costs have been recognized consistently. The effects of the subsidy have been reflected through lower tax expense included in rates. We believe we have reasonable assurance that the impacts related to the enactment of the Act are recoverable through rates in future periods. Therefore, the amounts related to Detroit Edison of $18 million and MichCon of $4 million have been deferred as Regulatory Assets. See Note 13 of the Notes to Consolidated Financial Statements.

FAIR VALUE

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Contracts we typically classify as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items we do not generally account for as derivatives include proprietary gas inventory, power transmission, pipeline transportation and certain storage assets. See Notes 4 and 5 of the Notes to Consolidated Financial Statements.

As a result of adherence to generally accepted accounting principles, the tables below do not include the expected earnings impact of non-derivative gas storage, transportation and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reported period-by-period earnings; however, the financial impact of the timing differences will reverse at the time of physical delivery and/or settlement.

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

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

The following tables provide details on changes in our MTM net asset (or liability) position for the six months ended June 30, 2010:


(in Millions)	Total
MTM at December 31, 2009	$	(93	)

Reclassify to realized upon settlement		46
Changes in fair value recorded to income		73

Amounts recorded to unrealized income		119
Changes in fair value recorded in regulatory liabilities		3
Change in collateral held by (for) others		(41	)
Option premiums paid and other		(20	)

MTM at June 30, 2010	$	(32	)

The table below shows the maturity of our MTM positions:


										2013
(in Millions)										And			Total Fair
Source of Fair Value	2010			2011			2012			Beyond			Value
Level 1	$	9		$	12		$	(23	)	$	22		$	20
Level 2		(46	)		(112	)		(65	)		(36	)		(259	)
Level 3		26			87			48			—			161

Total MTM before netting adjustments	$	(11	)	$	(13	)	$	(40	)	$	(14	)	$	(78	)


Collateral adjustments													$	46


Total MTM at June 30, 2010													$	(32	)

Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Price Risk

We have commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

Our Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. However, we do not bear significant exposure to earnings risk as such changes are included in the form of PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas, storage sales revenue and uncollectible expenses at the Gas Utility. Gas Utility manages its market price risk related to storage sales revenue primarily through the sale of long-term storage contracts. We have tracking mechanisms to mitigate a portion of losses related to uncollectible accounts receivable at MichCon and Detroit Edison. We are exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

Our Gas Storage and Pipelines business segment has limited exposure to natural gas price fluctuations and manages its exposure through the sale of long-term storage and transportation contracts.

Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we may use forward energy and futures contracts.

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

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

Credit Risk

Bankruptcies

We purchase and sell 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 our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and records provisions for amounts considered at risk of probable loss. We believe our accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on our consolidated financial statements.

Other

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

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of June 30, 2010:


	Credit Exposure
	Before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade(1)
A- and Greater	$	224	$	(14	)	$	210
BBB+ and BBB		267		—			267
BBB-		56		—			56

Total Investment Grade		547		(14	)		533

Non-investment grade(2)		4		—			4
Internally Rated — investment grade(3)		114		(6	)		108
Internally Rated — non-investment grade(4)		10		—			10

Total	$	675	$	(20	)	$	655


(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 37 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 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 13 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 1 percent of the total gross credit exposure.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of June 30, 2010, we had a floating rate debt-to-total debt ratio of less than one percent (excluding securitized debt).

Foreign Currency Exchange Risk

We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency exchange fluctuations, we have entered into a series of foreign currency exchange forward contracts through January 2013. Additionally, we may enter into fair value foreign currency exchange hedges to mitigate changes in the value of contracts or loans.

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign currency exchange forward contracts. The commodity contracts and foreign currency exchange risk listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at June 30, 2010 and 2009 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of June 30, 2010 and 2009:


	Assuming a						Assuming a
	10% Increase in Rates						10% Decrease in Rates
(in Millions)	As of June 30,						As of June 30,
Activity	2010			2009			2010			2009			Change in the Fair Value of
Coal Contracts	$	(1	)	$	1		$	1		$	(1	)	Commodity contracts
Gas Contracts		(8	)		(8	)		8			9		Commodity contracts
Oil Contracts		2			2			(2	)		(2	)	Commodity contracts
Power Contracts		1			(13	)		1			13		Commodity contracts
Interest Rate Risk		(267	)		(310	)		287			336		Long-term debt
Foreign Currency Exchange Risk		2			(4	)		11			4		Forward contracts
Discount Rates		—			1			—			(1	)	Commodity contracts

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

Part I — Item 4.

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2010, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II — Other Information

Item 1. — Legal Proceedings

The Company is involved in certain 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 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.

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 Title V operating permit requirements under the Clean Air Act. In June 2010, EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant. We believe that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. The Company could also be required to install additional pollution control equipment at some or all of the power plants in question, consider 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.

Item 1A. — Risk Factors

There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we have provided a brief explanation of the more significant risks associated with our businesses in Part 1, Item 1A. Risk Factors in the Company’s 2009 Form 10-K. Although we have tried to identify and discuss key risk factors, others could emerge in the future. In addition to the risk factors set forth in our 10-K, the following updated risk could affect our performance.

A work interruption may adversely affect us. Unions represent approximately 5,000 of our employees. A union choosing to strike would have an impact on our business. Our contracts with unions representing two small groups of employees expired on December 31, 2009 and another union is currently negotiating its first contract. We cannot predict the outcome of any of these contract negotiations, some of which have not yet commenced. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Securities Exchange Act of 1934 during the three months ended June 30, 2010:


					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
04/01/10 - 04/30/10		—	$	—		—		—
05/01/10 - 05/31/10		85,000		48.33		—		—
06/01/10 - 06/30/10		—		—		—		—

Total		85,000		48.33		—		—


(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.

Item 6. — Exhibits


Exhibit
Number		Description

Exhibits filed herewith:

31-59		Chief Executive Officer Section 302 Form 10-Q Certification

31-60		Chief Financial Officer Section 302 Form 10-Q Certification

Exhibits incorporated herein by reference:

3-7		Amended and Restated Articles of Incorporation (as amended May 6, 2010, effective May 11, 2010) (Exhibit 3.1 to Form 8-K dated May 6, 2010).

3-8		Amended Bylaws (as amended through May 6, 2010) (Exhibit 3.2 to Form 8-K dated May 6, 2010).

Exhibits furnished herewith:

32-59		Chief Executive Officer Section 906 Form 10-Q Certification

32-60		Chief Financial Officer Section 906 Form 10-Q Certification

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	DTE ENERGY COMPANY (Registrant)
Date: July 30, 2010	/s/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer