DTE Energy - 10-Q quarterly report FY2012 Q2

DTE Energy - 10-Q quarterly report FY2012 Q2

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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, 2012

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)



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

One Energy Plaza, Detroit, Michigan	48226-1279
(Address of principal executive offices)	(Zip Code)

313-235-4000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

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

Yes þ No o

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

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, 2012, 171,754,812 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, 2012

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	PAGE
DEFINITIONS	1
FORWARD-LOOKING STATEMENTS	3
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements	4
Consolidated Statements of Operations (Unaudited)	4
Consolidated Statements of Comprehensive Income (Unaudited)	5
Consolidated Statements of Financial Position (Unaudited)	6
Consolidated Statements of Cash Flows (Unaudited)	8
Consolidated Statement of Changes in Equity (Unaudited)	9
Notes to Consolidated Financial Statements (Unaudited)	10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3. Quantitative and Qualitative Disclosures About Market Risk	46
Item 4. Controls and Procedures	48
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	48
Item 1A. Risk Factors	49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers	50
Item 6. Exhibits	51
SIGNATURE	52
EX-12-51
EX-31-75
EX-31-76
EX-32-75
EX-32-76
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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DEFINITIONS



ASC	Accounting Standards Codification

ASU	Accounting Standards Update

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

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

Company	DTE Energy Company and any subsidiary companies

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

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

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

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

EPA	United States Environmental Protection Agency

FASB	Financial Accounting Standards Board

FERC	Federal Energy Regulatory Commission

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

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

MCIT	Michigan Corporate Income Tax

MDEQ	Michigan Department of Environmental Quality

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

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

MPSC	Michigan Public Service Commission

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

NRC	United States Nuclear Regulatory Commission

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

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

PSCR	A Power Supply Cost Recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power costs.

RDM	A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas.

Securitization	Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, The Detroit Edison Securitization Funding LLC.

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Subsidiaries	The direct and indirect subsidiaries of DTE Energy Company

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

VIE	Variable Interest Entity

Units of Measurement

Bcf	Billion cubic feet of gas

Bcfe	Conversion metric using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.

Btu	Heat value (energy content) of fuel

dth/d	Decatherms per day

kWh	Kilowatthour of electricity

MMBtu	Million Btu

Mcf	Thousand cubic feet of gas

MMcf	Million cubic feet of gas

MW	Megawatt of electricity

MWh	Megawatthour of electricity

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FORWARD-LOOKING STATEMENTS

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


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


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


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


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


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


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


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


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


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


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


•	the timing and extent of changes in interest rates;


•	the level of borrowings;


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


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


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


•	unplanned outages;


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


•	employee relations and the impact of collective bargaining agreements;


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


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


•	the effects of competition;


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


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


•	binding arbitration, litigation and related appeals; and


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

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

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Part I — Item 1.

DTE ENERGY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
	(In millions, except per share amounts)
Operating Revenues	$	2,025		$	2,028		$	4,274		$	4,459
Operating Expenses
Fuel, purchased power and gas	697			771			1,586			1,842
Operation and maintenance	708			647			1,434			1,278
Depreciation, depletion and amortization	250			248			482			493
Taxes other than income	79			77			174			160
Asset (gains) and losses, reserves and impairments, net	(3		)	(3		)	(8		)	8
	1,731			1,740			3,668			3,781
Operating Income	294			288			606			678
Other (Income) and Deductions
Interest expense	109			124			222			250
Interest income	(3		)	(2		)	(5		)	(5		)
Other income	(41		)	(18		)	(78		)	(39		)
Other expenses	12			8			19			15
	77			112			158			221
Income Before Income Taxes	217			176			448			457
Income Tax Expense (Benefit)	70			(24		)	143			79

Net Income	147			200			305			378

Less: Net Income (Loss) Attributable to Noncontrolling Interests	1			(2		)	3			—
Net Income Attributable to DTE Energy Company	$	146		$	202		$	302		$	378

Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	0.86		$	1.19		$	1.77		$	2.23

Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	0.86		$	1.19		$	1.77		$	2.23

Weighted Average Common Shares Outstanding
Basic	170			169			170			169
Diluted	171			170			171			170
Dividends Declared per Common Share	$	0.59		$	0.59		$	1.18		$	1.15

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012		2011
	(In millions)
Net income	$	147		$	200		$	305	$	378
Other comprehensive income, net of tax:
Benefit obligations, net of taxes of $1, $—, $3 and $1, respectively	3			1			6		2
Net unrealized gains on investments, net of taxes of $—, $—, $— and $—, respectively	—			—			1		—
Foreign currency translation, net of taxes of $—, $—, $— and $—, respectively	(1		)	1			—		1
Comprehensive income	149			202			312		381
Less: Comprehensive income attributable to noncontrolling interests	1			(2		)	3		—
Comprehensive income attributable to DTE Energy Company	$	148		$	204		$	309	$	381

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)



	June 30			December 31
	2012			2011
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	185		$	68
Restricted cash, principally Securitization	110			147
Accounts receivable (less allowance for doubtful accounts of $153 and $162, respectively)
Customer	1,239			1,317
Other	164			90
Inventories
Fuel and gas	487			572
Materials and supplies	223			219
Deferred income taxes	65			51
Derivative assets	221			222
Regulatory assets	194			314
Other	162			196
	3,050			3,196
Investments
Nuclear decommissioning trust funds	985			937
Other	533			525
	1,518			1,462
Property
Property, plant and equipment	23,081			22,541
Less accumulated depreciation, depletion and amortization	(8,929		)	(8,795		)
	14,152			13,746
Other Assets
Goodwill	2,020			2,020
Regulatory assets	4,390			4,539
Securitized regulatory assets	497			577
Intangible assets	67			73
Notes receivable	117			123
Derivative assets	75			74
Other	189			199
	7,355			7,605
Total Assets	$	26,075		$	26,009

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED) — (Continued)



	June 30			December 31
	2012			2011
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	728		$	782
Accrued interest	94			95
Dividends payable	207			99
Short-term borrowings	39			419
Current portion long-term debt, including capital leases	848			526
Derivative liabilities	211			158
Other	508			549
	2,635			2,628
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,528			6,405
Securitization bonds	391			479
Junior subordinated debentures	280			280
Capital lease obligations	13			23
	7,212			7,187
Other Liabilities
Deferred income taxes	3,263			3,116
Regulatory liabilities	1,007			1,019
Asset retirement obligations	1,641			1,591
Unamortized investment tax credit	60			65
Derivative liabilities	62			89
Accrued pension liability	1,224			1,298
Accrued postretirement liability	1,341			1,484
Nuclear decommissioning	149			148
Other	297			331
	9,044			9,141
Commitments and Contingencies (Notes 6 and 11)
Equity
Common stock, without par value, 400,000,000 shares authorized, 171,754,812 and 169,247,282 shares issued and outstanding, respectively	3,549			3,417
Retained earnings	3,744			3,750
Accumulated other comprehensive loss	(151		)	(158		)
Total DTE Energy Company Equity	7,142			7,009
Noncontrolling interests	42			44
Total Equity	7,184			7,053
Total Liabilities and Equity	$	26,075		$	26,009

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	Six Months Ended
	June 30
	2012			2011
	(In millions)
Operating Activities
Net income	$	305		$	378
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	482			493
Deferred income taxes	81			14
Asset (gains) and losses, reserves and impairments, net	(7		)	8
Changes in assets and liabilities, exclusive of changes shown separately (Note 14)	300			266
Net cash from operating activities	1,161			1,159
Investing Activities
Plant and equipment expenditures — utility	(708		)	(684		)
Plant and equipment expenditures — non-utility	(131		)	(35		)
Proceeds from sale of assets	15			9
Restricted cash for debt redemption, principally Securitization	15			2
Proceeds from sale of nuclear decommissioning trust fund assets	36			59
Investment in nuclear decommissioning trust funds	(44		)	(76		)
Other	(15		)	(42		)
Net cash used for investing activities	(832		)	(767		)
Financing Activities
Issuance of long-term debt	496			547
Redemption of long-term debt	(140		)	(721		)
Short-term borrowings, net	(380		)	1
Issuance of common stock	20			—
Repurchase of common stock	—			(18		)
Dividends on common stock	(199		)	(190		)
Other	(9		)	(15		)
Net cash used for financing activities	(212		)	(396		)
Net Increase (Decrease) in Cash and Cash Equivalents	117			(4		)
Cash and Cash Equivalents at Beginning of Period	68			65
Cash and Cash Equivalents at End of Period	$	185		$	61

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)



							Accumulated Other Comprehensive Loss			Non-Controlling Interest
	Common Stock			Retained Earnings
	Shares	Amount		Retained Earnings									Total
	(Dollars in millions, shares in thousands)
Balance, December 31, 2011	169,247	$	3,417	$	3,750		$	(158	)	$	44		$	7,053
Net Income	—	—		302			—			3			305
Dividends declared on common stock	—	—		(307		)	—			—			(307		)
Issuance of common stock	363	20		—			—			—			20
Contribution of common stock to pension plan	1,335	80											80
Benefit obligations, net of tax	—	—		—			6			—			6
Net change in unrealized losses on investments, net of tax	—	—		—			1			—			1
Stock-based compensation, distributions to noncontrolling interests and other	810	32		(1		)	—			(5		)	26
Balance, June 30, 2012	171,755	$	3,549	$	3,744		$	(151	)	$	42		$	7,184

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:


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


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


•	Other businesses involved in 1) natural gas pipelines, gathering and storage; 2) unconventional gas and oil project development and production; 3) power and industrial projects; and 4) energy marketing and trading operations.

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

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 2011 Annual Report on Form 10-K.

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

The Consolidated Financial Statements are unaudited, but in the Company’s opinion include all adjustments necessary to a fair statement of the results for the interim periods. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2012.

Principles of Consolidation

The Company consolidates all majority owned subsidiaries and investments in entities in which it has controlling influence. Non-majority owned investments are accounted for using the equity method when the Company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When the Company does not influence the operating policies of an investee, the cost method is used. These Consolidated Financial Statements also reflect the Company’s proportionate interests in certain jointly owned utility plant. The Company eliminates all intercompany balances and transactions.

The Company 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 evaluates whether an entity is a VIE whenever reconsideration events occur. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

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

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of June 30, 2012, the carrying amount of assets and liabilities in the Consolidated Statements of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

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

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

The following table summarizes the major balance sheet items for consolidated VIEs as of June 30, 2012 and December 31, 2011. Amounts at June 30, 2012 and December 31, 2011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below (in millions):



	June 30, 2012								December 31, 2011
	Securitization		Other		Total		Restricted Amounts		Securitization		Other		Total		Restricted Amounts
ASSETS
Cash and cash equivalents	$	—	$	18	$	18	$	—	$	—	$	25	$	25	$	—
Restricted cash	92		7		99		99		107		7		114		114
Accounts receivable	37		16		53		39		34		17		51		36
Inventories	—		151		151		—		—		183		183		—
Other current assets	—		3		3		—		—		1		1		—
Property, plant and equipment	—		70		70		21		—		73		73		23
Securitized regulatory assets	497		—		497		497		577		—		577		577
Other assets	9		6		15		15		10		6		16		16
	$	635	$	271	$	906	$	671	$	728	$	312	$	1,040	$	766
LIABILITIES
Accounts payable and accrued current liabilities	$	12	$	40	$	52	$	13	$	14	$	24	$	38	$	14
Current portion long-term debt, including capital leases	168		8		176		176		164		7		171		171
Other current liabilities	48		—		48		48		55		—		55		55
Mortgage bonds, notes and other	—		27		27		27		—		30		30		30
Securitization bonds	391		—		391		391		479		—		479		479
Capital lease obligations	—		12		12		12		—		14		14		14
Other long-term liabilities	7		2		9		8		7		2		9		8
	$	626	$	89	$	715	$	675	$	719	$	77	$	796	$	771

Amounts for non-consolidated VIEs as of June 30, 2012 and December 31, 2011 are as follows (in millions):



	June 30, 2012		December 31, 2011
Other investments	$	121	$	117
Notes receivable	7		7

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NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Summary of intangible assets as of June 30, 2012 and December 31, 2011 (in millions):



	June 30, 2012		December 31, 2011
Emission allowances	$	8	$	10
Renewable energy credits	42		39
Contract intangible assets	64		65
	114		114
Less accumulated amortization	29		28
Intangible assets, net	85		86
Less current intangible assets	18		13
	$	67	$	73

Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years.

Income Taxes

The Company's effective tax rate from continuing operations for the three and six months ended June 30, 2012 is 32 percent and 32 percent, respectively, as compared to a negative 14 percent and 17 percent for the three and six months ended June 30, 2011, respectively. The increase in the effective tax rate in 2012 is due primarily to the recognition of an $88 million income tax benefit due to the enactment of the Michigan Corporate Income Tax in the second quarter of 2011.

The Company had $3 million and $4 million of unrecognized tax benefits at June 30, 2012 and at December 31, 2011, respectively, that, if recognized, would favorably impact its effective tax rate. In 2012, the Company settled a federal tax audit for the 2009 and 2010 tax years and, as a result, the unrecognized tax benefit decreased by $30 million. The Company does not anticipate any material changes to the unrecognized tax benefits 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 the Company’s total assets and total liabilities. As of June 30, 2012 , the total cash collateral received, net of cash collateral posted, was $11 million. There was no collateral related to unrealized positions to net against derivative assets and liabilities as of June 30, 2012. As of June 30, 2012, the Company recorded cash collateral paid of $6 million and cash collateral received of $17 million not related to unrealized derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

NOTE 3 — FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at June 30, 2012 and December 31, 2011. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

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

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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.

Cash Equivalents

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

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through 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. The Company has established a Risk Management Committee whose responsibilities include directly or indirectly ensuring all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our Risk Management group, which is part of the corporate treasury function. This group is separate and distinct from the trading functions within the Company.

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The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2012 and December 31, 2011 (in millions):



	June 30, 2012															December 31, 2011
	Level 1			Level 2			Level 3			Netting (b)			Net Balance			Level 1			Level 2			Level 3			Netting (b)			Net Balance
Assets:
Cash equivalents	$	—		$	115		$	—		$	—		$	115		$	—		$	140		$	—		$	—		$	140
Nuclear decommissioning trusts	624			361			—			—			985			577			360			—			—			937
Other investments (a)	61			41			—			—			102			57			38			—			—			95
Derivative assets:
Foreign currency exchange contracts	—			1			—			(1		)	—			—			3			—			(3		)	—
Commodity Contracts:
Natural Gas	966			72			35			(1,037		)	36			1,926			78			20			(1,991		)	33
Electricity	—			549			270			(569		)	250			—			523			224			(490		)	257
Other	51			5			6			(52		)	10			23			2			6			(25		)	6
Total derivative assets	1,017			627			311			(1,659		)	296			1,949			606			250			(2,509		)	296
Total	$	1,702		$	1,144		$	311		$	(1,659	)	$	1,498		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468

Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(1	)	$	—		$	1		$	—		$	—		$	(5	)	$	—		$	3		$	(2	)
Interest rate contracts	—			(1		)	—			—			(1		)	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(944		)	(113		)	(33		)	1,037			(53		)	(1,940		)	(126		)	(14		)	1,976			(104		)
Electricity	—			(576		)	(220		)	569			(227		)	—			(513		)	(192		)	565			(140		)
Other	(42		)	(1		)	(1		)	52			8			(19		)	(1		)	—			20			—
Total derivative liabilities	(986		)	(692		)	(254		)	1,659			(273		)	(1,959		)	(646		)	(206		)	2,564			(247		)
Total	$	(986	)	$	(692	)	$	(254	)	$	1,659		$	(273	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	716		$	452		$	57		$	—		$	1,225		$	624		$	498		$	44		$	55		$	1,221
Assets:
Current	$	804		$	648		$	248		$	(1,364	)	$	336		$	1,571		$	660		$	181		$	(2,050	)	$	362
Noncurrent (c)	898			496			63			(295		)	1,162			1,012			484			69			(459		)	1,106
Total Assets	$	1,702		$	1,144		$	311		$	(1,659	)	$	1,498		$	2,583		$	1,144		$	250		$	(2,509	)	$	1,468
Liabilities:
Current	$	(785	)	$	(588	)	$	(202	)	$	1,364		$	(211	)	$	(1,603	)	$	(527	)	$	(152	)	$	2,124		$	(158	)
Noncurrent	(201		)	(104		)	(52		)	295			(62		)	(356		)	(119		)	(54		)	440			(89		)
Total Liabilities	$	(986	)	$	(692	)	$	(254	)	$	1,659		$	(273	)	$	(1,959	)	$	(646	)	$	(206	)	$	2,564		$	(247	)
Net Assets at the end of the period	$	716		$	452		$	57		$	—		$	1,225		$	624		$	498		$	44		$	55		$	1,221

_____________________________


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


(b)	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.


(c)	Includes $102 million and $95 million of other investments that are included in the Consolidated Statements of Financial Position in Other investments at June 30, 2012 and December 31, 2011, respectively.

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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, 2012 and 2011 (in millions):



	Three Months Ended												Three Months Ended
	June 30, 2012												June 30, 2011
	Natural Gas			Electricity			Other			Total			Natural Gas			Electricity			Other			Total
Net Assets at the beginning of the period	$	6		$	25		$	6		$	37		$	3		$	8		$	5		$	16
Transfers into Level 3	1			—			—			1			(3		)	62			—			59
Transfers out of Level 3	—			—			—			—			—			(2		)	—			(2		)
Total gains:
Included in earnings	(1		)	56			(3		)	52			3			8			—			11
Recorded in regulatory assets/liabilities	—			—			4			4			—			—			4			4
Purchases, issuances and settlements:
Purchases	—			—			—			—			—			1			—			1
Settlements	(4		)	(31		)	(2		)	(37		)	(2		)	(20		)	(2		)	(24		)
Net Assets at the end of the period	$	2		$	50		$	5		$	57		$	1		$	57		$	7		$	65
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at June 30, 2012 and 2011and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	(2	)	$	38		$	(3	)	$	33		$	2		$	2		$	—		$	4



	Six Months Ended													Six Months Ended
	June 30, 2012													June 30, 2011
	Natural Gas			Electricity			Other				Total			Natural Gas			Electricity			Other			Total
Net Assets at the beginning of the period	$	6		$	32		$	6			$	44		$	1		$	54		$	4		$	59
Transfers into Level 3	1			28			—				29			—			73			—			73
Transfers out of Level 3	(2		)	—			—				(2		)	1			(25		)	—			(24		)
Total gains:
Included in earnings	6			41			(2		)		45			(2		)	(18		)	2			(18		)
Recorded in regulatory assets/liabilities	—			—			5				5			—			—			3			3
Purchases, issuances and settlements:
Purchases	—			—			—			—	—			—			1			—			1
Settlements	(9		)	(51		)	(4		)	—	(64		)	1			(28		)	(2		)	(29		)
Net Assets at the end of the period	$	2		$	50		$	5			$	57		$	1		$	57		$	7		$	65
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at June 30, 2012 and 2011and reflected in Operating revenues and Fuel, purchased power and gas in the Consolidated Statements of Operations	$	4		$	38		$	(2	)		$	40		$	(1	)	$	(17	)	$	2		$	(16	)

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

30, 2012 and 2011 (in millions):



	Three Months Ended						Three Months Ended
	June 30, 2012						June 30, 2011
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		—		$	—	N/A		2
Transfers into Level 3 from	—		1		N/A		—		59		N/A

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	Six Months Ended						Six Months Ended
	June 30, 2012						June 30, 2011
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Transfers into Level 1 from	N/A		$	—	$	—	N/A		$	—	$	—
Transfers into Level 2 from	$	—	N/A		2		$	—	N/A		24
Transfers into Level 3 from	—		29		N/A		—		73		N/A

The following table presents the unobservable inputs related to Level 3 assets and liabilities as of June 30, 2012 (in millions):



	June 30, 2012
Commodity Contracts	Derivative Assets		Derivative Liabilities			Valuation Techniques	Unobservable Input	Range
Natural Gas	$	35	$	(33	)	Discounted Cash Flow	Forward basis price (per MMBtu)	$	(0.32	)	—	$	1.68	/MMBtu
Electricity	270		(220		)	Discounted Cash Flow	Forward market price (per Mwh)	13			—	23		/Mwh
							Forward basis price (per Mwh)	(1		)	—	16		/Mwh

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

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

Fair Value of Financial Instruments

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

The following table presents the carrying amount and fair value of financial instruments as of June 30, 2012 and December 31, 2011 (in millions):



	June 30, 2012								December 31, 2011
	Carrying		Fair Value						Carrying		Fair
	Amount		Level 1		Level 2		Level 3		Amount		Value
Notes receivable, excluding capital leases	$	44	$	—	$	—	$	44	$	48	$	48
Dividends payable	207		207		—		—		99		99
Short-term borrowings	39		—		39		—		419		419
Long-term debt	8,041		316		8,245		613		7,682		8,757

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

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. 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. See Note 5.

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The following table summarizes the fair value of the nuclear decommissioning trust fund assets (in millions):



	June 30, 2012		December 31, 2011
Fermi 2	$	960	$	915
Fermi 1	3		3
Low level radioactive waste	22		19
Total	$	985	$	937

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 (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Realized gains	$	8		$	12		$	14		$	26
Realized losses	(7		)	(9		)	(11		)	(17		)
Proceeds from sales of securities	25			39			36			59

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the Regulatory asset and Nuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:



	June 30, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Equity securities	$	581	$	102	$	533	$	80
Debt securities	397		26		385		22
Cash and cash equivalents	7		—		19		—
	$	985	$	128	$	937	$	102

The debt securities at both June 30, 2012 and December 31, 2011 had an average maturity of approximately 7 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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. Detroit Edison recognized $65 million and $67 million of unrealized losses as Regulatory assets at June 30, 2012 and December 31, 2011, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized for the three and six months ended June 30, 2012 and June 30, 2011 for Fermi 1 trust assets.

Other Available-For-Sale Securities

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



	June 30, 2012		December 31, 2011
	Fair Value		Fair Value
Cash equivalents (a)	$	115	$	140
Equity securities (b)	6		5

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(a)	Cash equivalents at June 30, 2012 of $99 million and $16 million are included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively. Cash equivalents at December 31, 2011 of $124 million and $16 million are included in Restricted cash and Other investments on the Consolidated Statements of Financial Position, respectively.


(b)	Equity securities at June 30, 2012 and December 31, 2011 of $6 million and $5 million are included in Other investments on the Consolidated Statements of Financial Position, respectively.

At June 30, 2012 and 2011, these securities are comprised primarily of money-market and equity securities. During the three and six months ended June 30, 2012 and June 30, 2011 no amounts of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income into losses for the periods. Gains related to trading securities held at June 30, 2012, and 2011, were $5 million and $4 million, respectively.

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NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

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

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

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

Gas Utility — MichCon purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through March 2015. 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. Primarily fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

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

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

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

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

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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 Accumulated other comprehensive loss will be reclassified to Interest expense through 2033. In 2012, the Company estimates reclassifying less than $1 million of losses to earnings.

Credit Risk — The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its June 30, 2012 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

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

•

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


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


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


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

The following tables present the fair value of derivative instruments as of June 30, 2012 and December 31, 2011 (in millions):



	June 30, 2012					December 31, 2011
	Derivative Assets		Derivative Liabilities			Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	1	$	(1	)	$	3	$	(5	)
Commodity Contracts:
Natural Gas	1,073		(1,090		)	2,024		(2,080		)
Electricity	819		(796		)	747		(705		)
Other	62		(44		)	31		(20		)
Total derivatives not designated as hedging instruments:	$	1,955	$	(1,931	)	$	2,805	$	(2,810	)
Total derivatives:
Current	$	1,585	$	(1,575	)	$	2,272	$	(2,282	)
Noncurrent	370		(357		)	533		(529		)
Total derivatives	$	1,955	$	(1,932	)	$	2,805	$	(2,811	)

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	June 30, 2012												December 31, 2011
	Derivative Assets						Derivative Liabilities						Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,585		$	370		$	(1,575	)	$	(357	)	$	2,272		$	533		$	(2,282	)	$	(529	)
Counterparty netting	(1,364		)	(295		)	1,364			295			(2,050		)	(440		)	2,050			440
Collateral adjustment	—			—			—			—			—			(19		)	74			—
Total derivatives as reported	$	221		$	75		$	(211	)	$	(62	)	$	222		$	74		$	(158	)	$	(89	)

The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and six months ended June 30, 2012 and June 30, 2011 is as follows (in millions):



	Location of Gain (Loss) Recognized in Income on Derivatives	Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended June 30					Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30
Derivatives not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	2012		2011			2012			2011
Foreign currency exchange contracts	Operating Revenue	$	1	$	1		$	1		$	(5	)
Commodity Contracts:
Natural Gas	Operating Revenue	1		9			3			15
Natural Gas	Fuel, purchased power and gas	5		(4		)	(5		)	(10		)
Electricity	Operating Revenue	37		30			35			29
Other	Operating Revenue	3		2			11			8
Total		$	47	$	38		$	45		$	37

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position was $4 million and $5 million in gains related to FTRs recognized in Regulatory liabilities for the three and six months ended June 30, 2012, respectively.

The following represents the cumulative gross volume of derivative contracts outstanding as of June 30, 2012:



Commodity		Number of Units
Natural Gas (MMBtu)		699,643,452
Electricity (MWh)		48,635,782
Foreign Currency Exchange ($ CAD)		21,635,737
FTR (MWh)		10,275,179

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, 2012, 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 $309 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.

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NOTE 5 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the six months ended June 30, 2012 follows (in millions):



Asset retirement obligations at December 31, 2011	$	1,593
Accretion	49
Revision in estimated cash flows	1
Liabilities settled	(2		)
Asset retirement obligations at June 30, 2012	$	1,641

NOTE 6 — REGULATORY MATTERS

2009 Electric Rate Case Filing - Court of Appeals Decision

On April 10, 2012, the Michigan Court of Appeals issued a decision relating to an appeal of the January 2010 MPSC order in Detroit Edison's January 2009 rate case filing. The order by the Court of Appeals is subject to further appellate review.

The Court determined that the MPSC only had statutory authority to implement a Revenue Decoupling Mechanism (RDM) for gas providers, but not for electric providers, thereby reversing the MPSC's decision to authorize an RDM for Detroit Edison. As discussed below, Detroit Edison has accrued RDM refund liabilities of $56 million and $71 million for the 2010 and 2011 RDM reconciliation periods, respectively. It is the Company's interpretation that the parties in this proceeding have until July 30, 2012 to appeal the decision to the Michigan Supreme Court. Detroit Edison continues to retain the RDM liabilities until it is able to make a determination that the estimation of the liability should be revised. If the Court of Appeals decision is not appealed, Detroit Edison is considering filing an application with the MPSC requesting authority to defer the gain that will arise from the reversal of the RDM liabilities by establishing a new regulatory liability to be refunded to customers through a deferral of base rate increases expected to be needed in future years.

The Court found that the record of evidence in the 2009 rate case order was insufficient to support the MPSC's authorization to recover costs for the pilot advanced metering infrastructure (AMI) program and remanded this matter to the MPSC. The MPSC had approved $37 million of rate base related to the AMI program in the January 2010 order. Detroit Edison is currently operating its AMI program pursuant to the MPSC's approval set forth in its October 20, 2011 order, which was not reviewed by or subject to the Court of Appeal's April 10, 2012 decision. Detroit Edison will provide the necessary data and evidence to the MPSC supporting the AMI program expenditures at the remand hearing. Detroit Edison's AMI program expenditures are $90 million as of June 30, 2012, net of Department of Energy matching grant funds of $58 million.

The Court affirmed the use of tracking mechanisms (restoration, line clearance, uncollectibles expense and choice incentive) and the peak demand computations approved in the January 2010 order.

Detroit Edison RDM

In May 2011, Detroit Edison filed an application with the MPSC for approval of its initial pilot RDM reconciliation for the period February 2010 through January 2011, requesting authority to refund to customers approximately $56 million, plus interest. This amount was accrued by Detroit Edison at December 31, 2011. There are various interpretations and alternative calculation methodologies relating to the pilot RDM refund calculation that could ultimately be adopted by the MPSC which may result in a range of customer refund amounts from $56 million to $140 million for this initial reconciliation filing under the pilot RDM.

Detroit Edison accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest at December 31, 2011. Detroit Edison terminated the pilot RDM effective October 2011, and has requested a rehearing on this issue asserting that for reconciliation purposes, the pilot RDM should have been considered terminated in April 2011, when Detroit Edison self-implemented rates, consistent with prior MPSC orders. An April 2011 termination would result in a decrease to the liability. However, there can be no assurance that Detroit Edison will prevail in this matter. Similar to the initial reconciliation case, there are various interpretations and alternative calculation methodologies that could be adopted which may result in a range of refund obligations in excess of the amount accrued. Considering these variables, the potential customer refund amount could range from $10 million to $130 million for the second and final pilot RDM period.

The primary uncertainties involved in the calculation methodologies of the pilot RDM for both reconciliation periods include customer class groupings and treatment of fixed customer charges. The Company believes that the calculation methodology used and the resulting refund estimates recorded follow the requirements and intent of the MPSC orders and represent the most probable amount of Detroit Edison's pilot RDM refund liability as of June 30, 2012.

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In light of the Court of Appeals decision, actions related to the RDM reconciliation periods have been suspended pending further appellate review. Detroit Edison's RDM liabilities will be retained until Detroit Edison is able to make a determination that the estimation of the liability should be revised.

Energy Optimization (EO) Plans

In September 2011, Detroit Edison and MichCon filed biennial EO plans with the MPSC as required. Detroit Edison's EO plan application proposed the recovery of EO expenditures for the period 2012-2015 of $294 million and further requested approval of surcharges to recover these costs. MichCon's EO plan application proposed the recovery of EO expenditures for the period 2012-2015 of $103 million and further requested approval of surcharges to recover these costs. On April 17, 2012, the MPSC approved the EO plans proposed by Detroit Edison and MichCon subject to the utilities' agreement to certain modifications. On April 27, 2012, Detroit Edison and MichCon filed letters with the MPSC rejecting modifications to their EO plans. Accordingly, the amended 2010 EO plans remain in effect.

In May 2012, Detroit Edison and MichCon both filed separate applications for approval of their respective reconciliations of their 2011 EO plan expenses. Detroit Edison's EO reconciliation included a cumulative $23 million net over-recovery and MichCon's EO reconciliation included a cumulative $11 million net over-recovery. Detroit Edison and MichCon proposed that the calculated cumulative over-recoveries for 2011 be carried forward into 2012 and used as beginning balances for the 2012 reconciliations.

Vulnerable Household Warmth Fund

In December 2011, The Vulnerable Household Warmth Fund (VHWF) was created under Michigan law. The purpose of the fund is to provide payment or partial payment of bills for electricity, natural gas, propane, heating oil, or any other type of fuel used to heat the primary residence of a vulnerable customer during the 2011-2012 heating season. Effective with the new law, Detroit Edison and MichCon are to contribute the amounts collected in their base rates, previously remitted for the LIEEF, to the new VHWF. The monthly payments into the VHWF will cease on the earlier of September 30, 2012 or when $48 million has been accumulated in the fund from payments by major Michigan electric and gas utilities. In May 2012, Detroit Edison and MichCon filed applications requesting approval of per customer monthly credits to remove the annualized funding for the VHWF from rates in the amount of $40 million and $5 million, respectively. On July 13, 2012, the MPSC approved the plans to remove the VHWF from rates beginning in August 2012.

2012 Gas Rate Case Filing

MichCon filed a rate case on April 20, 2012 based on a projected test year for the twelve-month period ending October 31, 2013. The filing with the MPSC requested an increase in base rates of approximately $77 million that is required to recover higher costs associated with increased investments in plant, the impact of sales reductions due to customer losses and continuing conservation, and increasing operating costs, primarily pipeline integrity and leak remediation expenses. MichCon proposed in the filing, starting in 2013, a five-year annual incremental Infrastructure Recovery Mechanism to recover costs associated with capital investment for the meter move-out, main renewal and pipeline integrity programs. MichCon also proposed a modified form of its RDM.

MichCon RDM

In September 2011, MichCon filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. MichCon's RDM application proposed the recovery of approximately $20 million. On July 13, 2012, the MPSC approved a settlement agreement approving the RDM reconciliation and the implementation of a surcharge over a twelve-month period beginning in August 2012. As a result of the provisions of the settlement, during the quarter ended June 30, 2012, MichCon recognized an additional $5 million of revenue related to the 2010/2011 period and $3 million related to the 2011/2012 period.

MichCon Depreciation Filing

In June 2012, MichCon filed a depreciation study, as ordered by the MPSC, indicating an annual depreciation expense increase of $12.4 million. Depreciation rates remain unchanged pending the MPSC's consideration of the study.

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.

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2011-2012 GCR Year - In June 2012, MichCon filed its GCR reconciliation for the 12 months ending March 31, 2012. The net under-recovery of $6.4 million includes an over-recovery of $1 million for the 2010-2011 GCR year.

Other

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

NOTE 7 — COMMON STOCK

On June 18, 2012, the Company contributed $80 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was valued using the closing market price of DTE Energy common stock on that date in accordance with fair value measurement and accounting requirements.

NOTE 8 — EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options. A reconciliation of both calculations is presented in the following table as of June 30 (in millions, except per share amounts):



	Three Months Ended				Six Months Ended
	June 30				June 30
	2012		2011		2012		2011
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	146	$	202	$	302	$	378
Average number of common shares outstanding	170		169		170		169
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	100	$	99	$	200	$	194
Dividends declared — net restricted shares	1		—		1		—
Total distributed earnings	$	101	$	99	$	201	$	194
Net income less distributed earnings	$	45	$	103	$	101	$	184
Distributed (dividends per common share)	$	0.59	$	0.59	$	1.18	$	1.15
Undistributed	0.27		0.60		0.59		1.08
Total Basic Earnings per Common Share	$	0.86	$	1.19	$	1.77	$	2.23
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	146	$	202	$	302	$	378
Average number of common shares outstanding	170		170		170		170
Average incremental shares from assumed exercise of options	1		—		1		—
Common shares for dilutive calculation	171		170		171		170
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	100	$	99	$	200	$	194
Dividends declared — net restricted shares	1		—		1		—
Total distributed earnings	$	101	$	99	$	201	$	194
Net income less distributed earnings	$	45	$	103	$	101	$	184
Distributed (dividends per common share)	$	0.59	$	0.59	$	1.18	$	1.15
Undistributed	0.27		0.60		0.59		1.08
Total Diluted Earnings per Common Share	$	0.86	$	1.19	$	1.77	$	2.23

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NOTE 9 — LONG-TERM DEBT

Debt Issuances

In 2012, the Company issued the following long-term debt (in millions):



Company	Month	Type	Interest Rate		Maturity	Amount
Detroit Edison	June	Mortgage Bonds (a)	2.65	%	2022	$	250
Detroit Edison	June	Mortgage Bonds (a)	3.95	%	2042	250
						$	500

_____________________________


(a)	Proceeds to be used for the early redemption of Detroit Edison long-term debt; for the repayment of short-term borrowings; and for general corporate purposes.

Debt Retirements and Redemptions

In 2012, the following debt was retired, through payment at maturity (in millions):

Company

Month

Type

Interest Rate

Maturity

Amount

MichCon

May

Secured Medium Term Notes

7.06

2012

In July 2012, Detroit Edison redeemed $225 million of 5.2% senior notes due October 2012.

NOTE 10 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon, have unsecured revolving credit agreements with a syndicate of 20 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.5% 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 agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain MichCon short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At June 30, 2012, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon are 0.50 to 1, 0.54 to 1 and 0.46 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at June 30, 2012 is shown in the following table (in millions):



	DTE Energy		Detroit Edison		MichCon		Total
Unsecured letter of credit facility, expiring in May 2013	$	50	$	—	$	—	$	50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Unsecured revolving credit facility, expiring October 2016	1,100		300		400		1,800
Total credit facilities at June 30, 2012	$	1,275	$	300	$	400	$	1,975
Amounts outstanding at June 30, 2012:
Commercial paper issuances	39		—		—		39
Letters of credit	222		—		—		222
	261		—		—		261
Net availability at June 30, 2012	$	1,014	$	300	$	400	$	1,714

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $39 million which are used for various corporate purposes.

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At June 30, 2012, a $40 million letter of credit was in place, raising the capacity under this facility to $140 million. The $40 million letter of credit is included in the table above. The amount outstanding under this agreement was $70 million and $56 million at June 30, 2012 and December 31, 2011, respectively.

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NOTE 11 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze, mercury, and other air pollution. These rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. To comply with these requirements, Detroit Edison has spent approximately $1.7 billion through 2011. It is estimated that Detroit Edison will make capital expenditures of approximately $186 million in 2012 and up to approximately $2.0 billion of additional capital expenditures through 2021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving Detroit Edison temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). The Mercury and Air Toxics Standard (MATS) rule, formerly known as the Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The MATS rule requires reductions of mercury and other hazardous air pollutants beginning in 2015. Because these rules were recently finalized and technologies to comply are still being tested, it is not possible to quantify the impact of these rulemakings.

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

On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating.

On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. Briefs have been filed with the Court of Appeals. A decision by the Court of Appeals is not expected until late 2012. DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the appeals process, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

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 the EPA's use of this provision in determining best technology available for reducing environmental impacts. The EPA published a proposed rule in 2011 that extended the time line to 2020 with an estimated expected increase in costs to $80 million. The timing of the final rule is currently unknown. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.

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Contaminated and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At June 30, 2012 and December 31, 2011, the Company had $8 million accrued for remediation. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows.

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 repairs to the landfill embankment are expected to be completed by 2013.

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

Gas Utility

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

The MPSC established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of June 30, 2012 and December 31, 2011, the Company had $37 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. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.

Non-Utility

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

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

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In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a NOV/FOV from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a NOV in connection with these alleged violations. The Company has agreed to a Consent Order with the EPA to settle these historic air and water issues pursuant to which the Company will pay a fine of $1.75 million.

The Company received two NOVs from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend up to $1.5 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company may spend up to an additional $23 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.

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

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed and a re-proposal was issued by the EPA in December 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Based on the final approved regulations, anticipated in 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

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

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 of $490 million of coverage over a three-year period.

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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, subject to a $1 million deductible.

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 $31 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, 2012, 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. The DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel was terminated in 2011. Detroit Edison currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license.

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. In July 2012, Detroit Edison executed a settlement agreement with the federal government for costs associated with the DOE's delay in acceptance of spent nuclear fuel from Fermi 2 for permanent storage. The settlement provides for a payment of approximately $48 million, expected to be received in 2012, for delay-related costs experienced by Detroit Edison through 2010, and a claims process for submittal of delay-related costs from 2011 through 2013. The settlement proceeds will reduce the cost of the dry cask storage facility assets. The federal government continues to maintain its legal obligation to accept spent nuclear fuel from Fermi 2 for permanent storage. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

Synthetic Fuel Guarantees

The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as

of December 31, 2007. The Company provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at June 30, 2012 is approximately $1.2 billion. Payment under these guarantees is considered remote.

Reduced Emissions Fuel Guarantees

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at June 30, 2012 is approximately $44 million. Payment under these guarantees is considered remote.

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Other Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. The Company’s guarantees are not individually material with maximum potential payments totaling $10 million at June 30, 2012.

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, 2012, the Company had approximately $30 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. The Company is negotiating the contract with one union representing approximately 500 electrical linemen that is due to expire in August 2012. The majority of the remaining represented employees are under contracts that expire in June and October 2013.

Purchase Commitments

As of December 31, 2011, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.3 billion from 2012 through 2051.

The Company also estimates that 2012 capital expenditures will be approximately $1.9 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 governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

Other Contingencies

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

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

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NOTE 12 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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



	Pension Benefits						Other Postretirement Benefits
	2012			2011			2012			2011
Three Months Ended June 30
Service cost	$	20		$	18		$	18		$	17
Interest cost	51			50			31			31
Expected return on plan assets	(61		)	(61		)	(23		)	(23		)
Amortization of:
Net actuarial loss	43			33			20			15
Prior service cost (credit)	—			1			(7		)	(6		)
Settlements	—			2			—			—
Net periodic benefit cost	$	53		$	43		$	39		$	34



	Pension Benefits						Other Postretirement Benefits
	2012			2011			2012			2011
Six Months Ended June 30
Service cost	$	41		$	37		$	36		$	34
Interest cost	102			101			61			62
Expected return on plan assets	(122		)	(123		)	(46		)	(47		)
Amortization of:
Net actuarial loss	85			66			39			30
Prior service cost (credit)	—			2			(14		)	(13		)
Net transition liability	—			—			1			1
Settlements	2			2			—			—
Net periodic benefit cost	$	108		$	85		$	77		$	67

Pension and Other Postretirement Contributions

The Company contributed $80 million of DTE Energy common stock to its pension plans in the second quarter of 2012, consisting of approximately 1.3 million shares valued at an average price of $59.94 per share. At the discretion of management, and depending upon financial market conditions, the Company may make up to an additional $140 million contribution to its pension plans in 2012.

In January 2012, the Company contributed $140 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $120 million contribution to its other postretirement benefit plans in 2012.

NOTE 13 — STOCK-BASED COMPENSATION

The following table summarizes the components of stock-based compensation (in millions):



	Three Months Ended				Six Months Ended
	June 30				June 30
	2012		2011		2012		2011
Stock-based compensation expense	$	23	$	11	$	40	$	29
Tax benefit	9		4		15		11
Stock-based compensation cost capitalized in property, plant and equipment	1		1		2		2

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Stock Options

The following table summarizes our stock option activity for the six months ended June 30, 2012 (in millions):



	Number of Options		Weighted Average Exercise Price		Aggregate Intrinsic Value
Options outstanding at January 1, 2012	2,764,670		$	41.25
Granted	—		$	—
Exercised	(1,119,489	)	$	40.36
Forfeited or expired	(16,114	)	$	41.93
Options outstanding at June 30, 2012	1,629,067		$	41.86	$	24
Options exercisable at June 30, 2012	1,427,723		$	41.56	$	21

As of June 30, 2012, the weighted average remaining contractual life for the exercisable shares is 4.58 years. As of June 30, 2012, 201,344 options were non-vested. During the six months ended June 30, 2012, 332,026 options vested.

The intrinsic value of options exercised for the six months ended June 30, 2012 was $17 million. Total option expense recognized was $0.5 million and $1 million for the six months ended June 30, 2012 and 2011, respectively.

Restricted Stock Awards

The following table summarizes the Company’s restricted stock awards activity for the six months ended June 30, 2012:



	Restricted Stock		Weighted Average Grant Date Fair Value
Balance at January 1, 2012	726,224		$	42.25
Grants	156,470		$	53.26
Forfeitures	(4,904	)	$	43.78
Vested and issued	(241,508	)	$	33.64
Balance at June 30, 2012	636,282		$	48.05

Performance Share Awards

The following table summarizes the Company’s performance share activity for the six months ended June 30, 2012:



	Performance Shares
Balance at January 1, 2012	1,608,733
Grants	557,891
Forfeitures	(32,203	)
Payouts	(504,755	)
Balance at June 30, 2012	1,629,666

Unrecognized Compensation Costs

As of June 30, 2012, there was $80 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.46 years.

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NOTE 14 — SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended
	June 30
	2012			2011
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	120		$	65
Inventories	81			(23		)
Accrued pensions	6			(187		)
Accounts payable	(4		)	27
Income taxes payable/receivable	(39		)	242
Derivative assets and liabilities	26			(20		)
Gas inventory equalization	65			109
Postretirement obligation	(142		)	(55		)
Other assets	299			202
Other liabilities	(112		)	(94		)
	$	300		$	266



Noncash financing activities:
Common stock issued for employee benefit plans	$	80	$	1

NOTE 15 — SEGMENT AND RELATED INFORMATION

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

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

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

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

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

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 and marketing; and sell electricity from biomass-fired energy projects.

Energy Trading consists of energy marketing and trading operations.

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

The federal income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses if applicable. The 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.

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



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Electric Utility	$	8		$	9		$	15		$	18
Gas Utility	1			1			2			1
Gas Storage and Pipelines	3			4			4			6
Power and Industrial Projects	192			63			383			89
Energy Trading	10			15			24			37
Corporate and Other	(7		)	(11		)	(17		)	(28		)
	$	207		$	81		$	411		$	123

Financial data of the business segments follows (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues
Electric Utility	$	1,290		$	1,240		$	2,488		$	2,433
Gas Utility	214			242			723			931
Gas Storage and Pipelines	27			23			52			48
Unconventional Gas Production	12			10			22			18
Power and Industrial Projects	449			287			898			522
Energy Trading	239			306			500			628
Corporate and Other	1			1			2			2
Reconciliation & Eliminations	(207		)	(81		)	(411		)	(123		)
Total	$	2,025		$	2,028		$	4,274		$	4,459

Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	127		$	103		$	223		$	188
Gas Utility	4			(3		)	56			80
Gas Storage and Pipelines	17			14			34			29
Unconventional Gas Production	(2		)	(1		)	(3		)	(3		)
Power and Industrial Projects	10			5			18			15
Energy Trading	4			12			2			14
Corporate and Other (a)	(14		)	72			(28		)	55
Net Income Attributable to DTE Energy	$	146		$	202		$	302		$	378

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(a)	The 2011 net income for Corporate and Other includes an income tax benefit of $88 million related to the enactment of the MCIT in the second quarter of 2011.

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Part 1 — 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 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 2012 was $146 million, or $0.86 per diluted share, compared to net income attributable to DTE Energy of $202 million, or $1.19 per diluted share, in the second quarter of 2011. Net income attributable to DTE Energy in the six months ended June 30, 2012 was $302 million, or $1.77 per diluted share, compared to net income attributable to DTE Energy of $378 million, or $2.23 per diluted share, in the comparable period of 2011. The decreases in net income are primarily due to an income tax benefit of $88 million in the Corporate & Other segment related to the enactment of the MCIT in the second quarter of 2011. See Note 2 of the Notes to Consolidated Financial Statements.

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

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

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

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

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

CAPITAL INVESTMENTS

Our utility businesses require significant base capital investments each year in order to maintain and improve the reliability of their asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. Detroit Edison's capital investments over the 2012-2016 period are estimated at $4 billion for base capital investments, $1.3 billion to $1.8 billion for mandated environmental requirements and $900 million for renewable and energy efficiency expenditures. MichCon's capital investments over the 2012-2016 period are estimated at $675 million for base capital investments, $250 million for gas main renewal and $115 million for meter move out programs. MichCon proposed in its rate case filing on April 20, 2012, starting in 2013, a five-year annual incremental Infrastructure Recovery Mechanism to recover costs associated with capital investment for the meter move-out, main renewal and pipeline integrity programs. Detroit Edison and MichCon both plan to seek regulatory approval in general rate case filings to include these capital expenditures within their regulatory rate base consistent with prior general rate case filing treatment. Detroit Edison is implementing a 20-year renewable energy plan to address the provisions of Michigan Public Act 295 of 2008, with the goals of delivering cleaner renewable electric generation to its customers, further diversifying Detroit Edison's and the State of Michigan's sources of electric supply and addressing the state and national goals of increasing energy independence. Detroit Edison routinely files renewable energy plans, requests for approval of renewable contracts and for recovery of renewable capital expenditures with the MPSC as the implementation of the 20-year renewable energy plan progresses.

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.

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ENVIRONMENTAL MATTERS

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

Detroit Edison is subject to the EPA ozone and fine particulate transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. These rules will lead to additional 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 $1.7 billion through 2011. It is estimated that Detroit Edison will make capital expenditures of approximately $186 million in 2012 and up to approximately $2.0 billion of additional capital expenditures through 2021 based on current regulations.

Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA, however the current 112^th Congress is not expected to pass any major energy or climate bills. Meanwhile, the EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases (GHGs). EPA regulation of GHGs began in 2011 and requires the best available control technology (BACT) for new major sources or modifications to existing major sources that cause significant increases in GHG emissions. The impact of this rule is uncertain until BACT is better defined by the permitting agencies. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify these impacts on DTE Energy or its customers at this time.

See Note 11 of the Notes to the Consolidated Financial Statements for further discussion of Environmental Matters.

OUTLOOK

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

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


•	improving Electric and Gas Utility customer satisfaction;


•	continuing to improve employee engagement;


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


•	managing the growth of our utility asset base;


•	optimizing our cost structure across all business segments;


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


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

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

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RESULTS OF OPERATIONS

The following sections provide a detailed discussion of the operating performance and future outlook of our segments (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Net Income Attributable to DTE Energy by Segment:
Electric Utility	$	127		$	103		$	223		$	188
Gas Utility	4			(3		)	56			80
Gas Storage and Pipelines	17			14			34			29
Unconventional Gas Production	(2		)	(1		)	(3		)	(3		)
Power and Industrial Projects	10			5			18			15
Energy Trading	4			12			2			14
Corporate and Other	(14		)	72			(28		)	55
Net Income Attributable to DTE Energy Company	$	146		$	202		$	302		$	378

ELECTRIC UTILITY

Our Electric Utility segment consists principally of Detroit Edison. Electric Utility results are discussed below (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	$	1,290		$	1,240		$	2,488		$	2,433
Fuel and Purchased Power	428			417			805			795
Gross Margin	862			823			1,683			1,638
Operation and Maintenance	334			330			689			660
Depreciation and Amortization	204			204			391			407
Taxes Other Than Income	60			60			128			119
Asset (Gains) Losses, Reserves and Impairments, Net	(1		)	(5		)	(1		)	14
Operating Income	265			234			476			438
Other (Income) and Deductions	64			68			122			135
Income Tax Expense	74			63			131			115
Net Income Attributable to DTE Energy Company	$	127		$	103		$	223		$	188
Operating Income as a Percent of Operating Revenues	21		%	19		%	19		%	18		%

Gross margin increased $39 million in the second quarter of 2012 and $45 million in the six-month period ended June 30, 2012. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations. The following table details changes in various gross margin components relative to the comparable prior period (in millions):



	Three Months		Six Months
Base rate increase and weather, net of 2011 RDM	$	19	$	22
Renewable energy program	10		20
Energy optimization performance incentive	—		(9		)
Regulatory mechanisms and other, net	10		12
Increase in gross margin	$	39	$	45

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	Three Months Ended		Six Months Ended
	June 30		June 30
(In thousands of MWh)	2012	2011	2012	2011
Electric Sales
Residential	3,587	3,607	7,287	7,495
Commercial	4,247	3,998	8,132	7,991
Industrial	2,563	2,405	4,938	4,747
Other	221	763	479	1,560
	10,618	10,773	20,836	21,793
Interconnection sales (a)	859	1,156	1,385	1,461
Total Electric Sales	11,477	11,929	22,221	23,254
Electric Deliveries
Retail and Wholesale	10,618	10,773	20,836	21,793
Electric Customer Choice, including self generators	1,312	1,409	2,567	2,711
Total Electric Sales and Deliveries	11,930	12,182	23,403	24,504

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

Operation and maintenance expense increased $4 million and $29 million in the three and six months ended June 30, 2012, respectively. The increase for the 2012 second quarter is primarily due to higher employee benefit-related expense of $13 million, partially offset by lower uncollectible expense of $8 million. The increase for the 2012 six-month period is attributable to higher employee benefit-related expense of $20 million, increased restoration and line clearance expense of $7 million, and higher energy optimization and renewable energy expense of $5 million, partially offset by reduced uncollectible expense of $2 million.

Asset (gains) losses, reserves and impairments, net decreased in the first six months of 2012 due to a 2011 accrual of $19 million resulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a 2011 revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items.

Outlook — We continue to move forward in our efforts to achieve operational excellence, sustained strong cash flows and earn our authorized return on equity. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, additional factors may impact earnings such as the outcome of regulatory proceedings, 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 our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

See Note 6 of the Notes to Consolidated Financial Statements for discussion of the April 10, 2012 Michigan Court of Appeals decision relating to an appeal of the January 2010 MPSC order in Detroit Edison's January 2009 rate case filing.

In June 2012, our Fermi 2 nuclear power plant was manually shutdown after one of the plant's two feedwater pumps failed. After a detailed safety analysis and operational design plan, Detroit Edison has decided to operate the plant with one feedwater pump at a reduced power level until the second feedwater pump is returned to service. The start-up date of the plant and the expected power level have not yet been determined. We expect that any property damage will be covered by existing insurance coverage, subject to deductibles. We have been able to purchase sufficient power from MISO to continue to provide uninterrupted service to our customers. We do not expect the temporary shutdown and the operation of the plant at a reduced power level to have a significant impact on our results of operations.

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GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens. Gas Utility results are discussed below (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	$	214		$	242		$	723		$	931
Cost of Gas	62			95			338			501
Gross Margin	152			147			385			430
Operation and Maintenance	97			103			197			204
Depreciation and Amortization	23			22			46			44
Taxes Other Than Income	14			14			32			31
Operating Income	18			8			110			151
Other (Income) and Deductions	12			13			24			26
Income Tax Expense (Benefit)	2			(2		)	30			45
Net Income (Loss) Attributable to DTE Energy Company	$	4		$	(3	)	$	56		$	80
Operating Income as a Percent of Operating Revenues	8		%	3		%	15		%	16		%

Gross margin increased $5 million in the second quarter of 2012 and decreased $45 million in the six-month period ended June 30, 2012. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statements of Operations. The following table details changes in various gross margin components relative to the comparable prior period (in millions):



	Three Months			Six Months
Weather	$	(6	)	$	(56	)
RDM (a)	11			11
Lost gas	6			12
Uncollectible tracking mechanism	(4		)	(2		)
Other	(2		)	(10		)
Increase (decrease) in gross margin	$	5		$	(45	)

_____________________________


(a)	See Note 6 of the Notes to Consolidated Financial Statements for a discussion of the settlement agreement in MichCon's RDM reconciliation.



	Three Months Ended				Six Months Ended
	June 30				June 30
	2012		2011		2012		2011
Gas Markets (in millions)
Gas sales	$	132	$	162	$	538	$	733
End user transportation	45		40		109		117
Intermediate transportation	13		14		30		29
Storage and other	24		26		46		52
	$	214	$	242	$	723	$	931

Gas Markets (in Bcf)
Gas sales	14		18		61		80
End user transportation	34		27		82		79
	48		45		143		159
Intermediate transportation	61		62		144		145
	109		107		287		304

Operation and maintenance expense decreased $6 million and $7 million in the three and six months ended June 30, 2012, respectively. The decrease for the 2012 second quarter is primarily due to lower uncollectible expense of $6 million and lower gas operation expense of $2 million, partially offset by higher employee benefit-related expense of $1 million and higher energy optimization expenses of $1 million. The decrease for the 2012 six-month period is attributable to lower gas operations expense of $7 million and lower uncollectible expense of $5 million, partially offset by higher employee benefit-related expense of $2 million and higher energy optimization expense of $2 million.

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Outlook — We continue to move forward in our efforts to achieve operational excellence and sustained strong cash flows and earn our authorized return on equity. On April 20, 2012, we filed a rate case requesting an increase in revenues of approximately $77 million. We expect to self-implement new rates in the fourth quarter 2012 at the beginning of the heating season. Unfavorable economic trends have resulted in increased customer conservation and continued high levels of theft and uncollectible accounts receivable. The MPSC has provided for an uncollectible expense tracking mechanism which assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions and conservation. These tracking mechanisms and surcharges are expected to result in lower earnings volatility in the future. Looking forward, additional factors may impact earnings such as warmer than normal weather, infrastructure improvement capital programs, the outcome of future regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity, minimize lost and stolen gas, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

GAS STORAGE AND PIPELINES

Our Gas Storage and Pipelines segment consists of our non-utility gas pipelines and storage businesses. Gas Storage and Pipelines results are discussed below (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	$	27		$	23		$	52		$	48
Operation and Maintenance	6			3			10			7
Depreciation and Amortization	2			2			4			3
Taxes Other Than Income	1			1			2			2
Operating Income	18			17			36			36
Other (Income) and Deductions	(10		)	(6		)	(20		)	(13		)
Income Tax Expense	10			8			21			18
Net Income	18			15			35			31
Noncontrolling interest	1			1			1			2
Net Income Attributable to DTE Energy	$	17		$	14		$	34		$	29

Net income attributable to DTE Energy increased $3 million and $5 million for the 2012 second quarter and six-month period, respectively. The increases were due to higher revenues and increased earnings from an equity investment.

Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. Millennium Pipeline has secured customers for its Phase 1 and 2 expansions which are scheduled to be in-service in the fourth quarter of 2012 and the fourth quarter of 2013, respectively. Millennium's total capacity with the Phase 1 and 2 expansion will increase from 525,000 dth/d to over 800,000 dth/d. In addition, DTE has executed an agreement with Southwestern Energy Services Company to support our Bluestone lateral and gathering system. Bluestone is a 42 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow approximately 275,000 dth/d to both Millennium Pipeline and Tennessee Pipeline and is scheduled to be in service by the end of 2012. DTE plans to spend up to $280 million over the next five years on the Bluestone lateral and gathering system.

UNCONVENTIONAL GAS PRODUCTION

Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production within the Barnett shale and Marble Falls formation in northern Texas. Unconventional Gas Production results are discussed below (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	$	12		$	10		$	22		$	18
Operation and Maintenance	6			6			12			10
Depreciation, Depletion and Amortization	6			5			11			9
Taxes Other Than Income	1			—			1			1
Operating Income (Loss)	(1		)	(1		)	(2		)	(2		)
Other (Income) and Deductions	2			1			3			3
Income Tax Benefit	(1		)	(1		)	(2		)	(2		)
Net Loss Attributable to DTE Energy Company	$	(2	)	$	(1	)	$	(3	)	$	(3	)

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Net loss attributable to DTE Energy was impacted by higher gas and crude oil production, offset by decreased gas, natural gas liquids, and crude oil prices.

Outlook — We plan to focus on optimizing the productivity of our wells and to seek opportunities for monetization of properties in 2012. The majority of our acreage position has rights to shallow reserves lying above the Barnett shale, specifically the Marble Falls formation. Recent drilling efforts have been largely successful in finding oil and high Btu gas. We anticipate the continued development of these liquids which is expected to add value to our asset base. Based on a recent analysis, proved reserves have increased to 279 million Bcfe at June 2012 compared to 186 Bcfe at December 2011. The increase is due to results of improved completion techniques implemented on new wells drilled and brought on line in 2012. We expect total capital investment of $45 million to drill approximately 47 new wells and continue to acquire select acreage and achieve production of approximately 8 - 9 Bcfe in 2012, compared with 5 Bcfe in 2011. The majority of the drilling activity is expected to occur by the end of September 2012.

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, marketing and trading services; and sell electricity from biomass-fired energy projects. Power and Industrial Projects results are discussed below (in millions):



	Three Months Ended						Six Months Ended
	June 30						June 30
	2012			2011			2012			2011
Operating Revenues	$	449		$	287		$	898		$	522
Operation and Maintenance	444			261			883			467
Depreciation and Amortization	14			14			29			29
Taxes other than Income	3			1			9			5
Asset (Gains) Losses, Reserves and Impairments, Net	(2		)	3			(7		)	(6		)
Operating Income (Loss)	(10		)	8			(16		)	27
Other (Income) and Deductions	(11		)	5			(15		)	8
Income Taxes
Expense (Benefit)	—			2			(1		)	8
Production Tax Credits	(10		)	(2		)	(20		)	(3		)
	(10		)	—			(21		)	5
Net Income	11			3			20			14
Noncontrolling interest	1			(2		)	2			(1		)
Net Income Attributable to DTE Energy Company	$	10		$	5		$	18		$	15

Operating revenues increased $162 million and $376 million in the three and six months ended June 30, 2012, respectively. The increase in the second quarter of 2012 is primarily due to a $168 million increase related to new reduced emissions fuel projects (REF) and a $9 million increase associated with higher volumes from existing REF projects, of which $130 million represent affiliate transactions, partially offset by a $10 million decrease from lower volumes associated with the steel business, a $4 million decrease in coal transportation and marketing services primarily related to lower volumes and a $3 million decrease from lower volumes primarily associated with the on-site business. The increase in the six-month period is primarily due to a $338 million increase related to new REF projects and a $56 million increase associated with higher volumes from existing REF projects, of which $293 million represent affiliate transactions, and a $5 million increase due to higher volumes related to the on-site and renewable businesses, partially offset by a $12 million decrease in coal transportation and marketing services primarily related to lower volumes and an expired rail transportation contract, a $6 million decrease primarily associated with the expiration of a customer contract related to the on-site projects, and a $5 million decrease from lower volumes associated with the steel business.

Operation and maintenance expense increased $183 million and $416 million in the three and six months ended June 30, 2012, respectively. The increase in the second quarter of 2012 is primarily due to a $178 million increase related to new REF projects and an $8 million increase associated with higher volumes from existing REF projects, of which $132 million represent affiliate transactions, and an increase of $4 million due to the reserve of accounts receivable as a result of a customer bankruptcy in the steel business, partially offset by a $3 million decrease from lower volumes associated with the steel business, a $2 million decrease in coal transportation and marketing services primarily related to lower volumes and a $2 million decrease primarily associated with lower volumes from the on-site business. The increase in the six-month period is primarily due to a $353 million increase related to new REF projects and a $53 million increase associated with higher volumes from existing REF projects, of which $297 million represent affiliate transactions, a $11 million increase primarily due to higher coal costs associated with the steel business, and a $10 million increase primarily associated higher volumes from the on-site and renewable businesses, partially offset by an $11 million decrease in coal transportation and marketing services primarily related to lower volumes and an expired rail transportation contract.

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Other (income) and deductions increased by $16 million and $23 million in the three and six months ended June 30, 2012, respectively. The increases were due primarily to gains recognized in connection with the sale of membership interests in REF facilities (treated as sales of tax credits for financial reporting purposes).

Production tax credits were higher by $8 million and $17 million in the three and six months ended June 30, 2012, respectively, due primarily to tax credits earned from REF projects.

Outlook - The Company has constructed and placed in service nine REF facilities including two facilities located at third party owned coal-fired power plants. The Company has sold membership interests in two of the facilities located at the Detroit Edison sites. We continue to optimize these facilities by seeking tax investors for facilities operating at Detroit Edison and other utility sites. Additionally, we intend to relocate four underutilized facilities, located at Detroit Edison sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2012 and future years. One of the underutilized facilities is currently being relocated to a third party owned coal-fired power plant and will be operating in the new location by the end of 2012. The proceeds from executed and planned sales of membership interests in the REF facilities are expected to be received by the Company on an installment basis, and the Company will recognize the related gains (treated as sales of tax credits for financial reporting purposes) as production tax credits are generated by the respective facilities.

We expect reduced production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2012. Substantially all of the metallurgical coke is under long-term contracts. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. We have four waste-wood power generation facilities that are in operation in 2012, and we are converting an additional facility to be placed in service in 2013. During July 2012, we executed an agreement to purchase a portfolio of on-site energy projects, primarily located in the Midwest, at an expected purchase price of over $200 million. We expect the transaction to be consummated in 2012. We will continue to look for additional investment opportunities and other energy projects at favorable prices.

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

ENERGY TRADING

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



	Three Months Ended				Six Months Ended
	June 30				June 30
	2012		2011		2012		2011
Operating Revenues	$	239	$	306	$	500	$	628
Fuel, Purchased Power and Gas	210		271		456		567
Gross Margin	29		35		44		61
Operation and Maintenance	19		12		35		31
Depreciation and Amortization	—		—		—		1
Taxes Other Than Income	1		1		2		2
Operating Income	9		22		7		27
Other (Income) and Deductions	2		2		4		4
Income Tax Expense	3		8		1		9
Net Income Attributable to DTE Energy Company	$	4	$	12	$	2	$	14

Gross margin decreased $6 million in the second quarter of 2012 and decreased $17 million for the six months ended June 30, 2012. The overall decrease in gross margin for the second quarter was the result of timing-related losses, primarily in our gas strategies, and fewer market opportunities. The overall decrease in gross margin for the six months ended June 30, 2012 was a result of the unseasonably mild temperatures that negatively impacted our power and gas full requirements strategies and fewer market opportunities.

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The second quarter decrease of $6 million represents a $7 million decrease in realized margins and a $1 million increase in unrealized margins. The $7 million decrease in realized margins is due to $26 million of unfavorable results, primarily in our gas trading strategy. This was offset by $19 million of favorable results, primarily in our power trading and power full requirements strategies. The $1 million increase in unrealized margins is due to $22 million of favorable results, primarily in our gas trading strategy, offset by $21 million of unfavorable results, primarily in power full requirements, power transmission, and gas structured strategies.

The $17 million decrease for the six months ended represents a $12 million decrease in realized margins and $5 million decrease in unrealized margins. The $12 million decrease in realized margins is due to $29 million of unfavorable results, primarily in our gas trading, gas full requirements, and gas storage strategies, offset by $17 million of favorable results, primarily in our power trading and gas transportation strategies. The $5 million decrease in unrealized margins is due to $20 million of unfavorable results in our power full requirements, power trading, and power transmission strategies, offset by $15 million of favorable results, primarily in our gas trading strategy.

Operation and maintenance expense increased $7 million in the second quarter of 2012 and increased $4 million for the six months ended June 30, 2012 as compared to the same periods in 2011. This increase was primarily due to higher compensation costs.

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

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

See Note 3 of Notes to Consolidated Financial Statements.

CORPORATE AND OTHER

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

The net income for the second quarter of 2012 and six-month period ended June 30, 2012 decreased by $86 million and $83 million, respectively. The decrease in both periods is due primarily to an income tax benefit of $88 million related to the enactment of the MCIT in the second quarter of 2011.

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CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2012, we expect that cash from operations will be $1.9 billion due to lower working capital requirements. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2012 of approximately $1.9 billion, excluding the planned Power and Industrial Projects on-site energy project acquisition. We plan to seek regulatory approval to include utility capital expenditures in our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.



	Six Months Ended
	June 30
(In millions)	2012			2011
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	305		$	378
Depreciation, depletion and amortization	482			493
Deferred income taxes	81			14
Asset (gains) and losses, reserves and impairments, net	(7		)	8
Working capital and other	300			266
	$	1,161		$	1,159
Investing activities:
Plant and equipment expenditures — utility	(708		)	(684		)
Plant and equipment expenditures — non-utility	(131		)	(35		)
Proceeds from sale of assets	15			9
Other	(8		)	(57		)
	$	(832	)	$	(767	)
Financing activities:
Issuance of long-term debt	496			547
Redemption of long-term debt	(140		)	(721		)
Short-term borrowings, net	(380		)	—
Issuance of common stock	20			—
Repurchase of common stock	—			(18		)
Dividends on common stock and other	(208		)	(204		)
	$	(212	)	$	(396	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	117		$	(4	)

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, 2012 was consistent with 2011. The operating cash flow comparison reflects lower net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred income taxes and asset gains and losses), offset by increased cash generated from working capital items.

Cash from Investing Activities

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

Capital spending within the utility business is primarily to maintain and improve our electric generation and electric and gas distribution infrastructure and to comply with environmental regulations and renewable energy requirements.

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Capital spending within our non-utility businesses is primarily for ongoing maintenance 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 $65 million higher in 2012 due primarily to increased capital expenditures by our utility and non-utility businesses.

Cash from Financing Activities

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

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

Net cash used for financing activities was $184 million lower in 2012 due primarily to lower redemptions of long-term debt, partially offset by increased 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 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 primarily in our Gas Storage and Pipelines and Power and Industrial Projects segments. During July 2012, we executed an agreement to purchase a portfolio of on-site energy projects, primarily located in the Midwest, at an expected purchase price of over $200 million. We expect the transaction to be consummated in 2012. We will continue to look for additional investment opportunities and other energy projects at favorable prices.

We may be impacted by the delayed collection of underrecoveries of our various recovery and tracking mechanisms as a result of timing of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.

We have over $800 million in long-term debt maturing in the next twelve months. The repayment of the principal amount of debt related to Securitization is funded through a surcharge payable by Detroit Edison’s electric customers. The repayment of the other debt is expected to be refinanced with long-term debt.

DTE Energy has approximately $1.9 million of available liquidity at June 30, 2012 consisting of cash and amounts available under unsecured revolving credit agreements.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 provided for a special allowance for bonus depreciation in 2011 and 2012. Bonus depreciation is accelerated depreciation on certain types of business equipment that allows a tax deduction of either 50% or 100% of the cost of qualifying property in the year the asset is placed in service. DTE Energy expects to generate up to approximately $150 million in cash from 2012 bonus depreciation deductions, a significant portion of which is expected to result from Detroit Edison property, plant and equipment expenditures during the qualifying period. The cash benefit is an acceleration of tax deductions that the Company would otherwise have received over 20 years.

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.

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See Notes 6, 7, 9, 10 and 12 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 natural gas inventory, power transmission, pipeline transportation and certain storage assets. See Notes 3 and 4 of the Notes to Consolidated Financial Statements.

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

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

The following tables provide details on changes in our MTM net asset (or liability) position for the six months ended June 30, 2012 (in millions):



	Total
MTM at December 31, 2011	$	49
Reclassify to realized upon settlement	(30		)
Changes in fair value recorded to income	45
Amounts recorded to unrealized income	15
Changes in fair value recorded in regulatory liabilities	5
Change in collateral held by others	(56		)
Option premiums paid (received) and other	10
MTM at June 30, 2012	$	23

The table below shows the maturity of our MTM positions (in millions):



Source of Fair Value	2012			2013			2014		2015 and Beyond			Total Fair Value
Level 1	$	9		$	18		$	10	$	(6	)	$	31
Level 2	(25		)	(42		)	—		2			(65		)
Level 3	33			12			11		1			57
Total MTM before collateral adjustments	$	17		$	(12	)	$	21	$	(3	)	$	23
Collateral adjustments												—
Total MTM at June 30, 2012												$	23

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Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Price Risk

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

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

Our Gas Storage and Pipelines business segment has 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, natural gas liquids and 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

Other

MichCon has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in its last rate case. The uncollectible expense tracking mechanism requires annual reconciliation proceedings before the MPSC. See Note 6 of the Notes to Consolidated Financial Statements.

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

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internal credit assessments when determining the credit quality of our trading counterparties.

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The following table displays the credit quality of our trading counterparties as of June 30, 2012 (in millions):



	Credit Exposure Before Cash Collateral		Cash Collateral			Net Credit Exposure
Investment Grade (a)
A− and Greater	$	116	$	—		$	116
BBB+ and BBB	322		—			322
BBB−	83		—			83
Total Investment Grade	521		—			521
Non-investment grade (b)	6		—			6
Internally Rated — investment grade (c)	146		—			146
Internally Rated — non-investment grade (d)	21		(3		)	18
Total	$	694	$	(3	)	$	691

_____________________________


(a)	This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 39 percent of the total gross credit exposure.


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


(c)	This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 12 percent of the total gross credit exposure.


(d)	This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately two percent of the total gross credit exposure.

Interest Rate Risk

We are 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, 2012, we had a floating rate debt-to-total debt ratio of approximately five 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 gas and power as well as for long-term gas transportation capacity. To limit our exposure to foreign currency exchange fluctuations, we have entered into a series of foreign currency exchange forward contracts through July 2016.

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, 2012 and 2011 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of June 30, 2012 and 2011 (in millions):



	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
	As of June 30,						As of June 30,
Activity	2012			2011			2012			2011			Change in the Fair Value of
Coal Contracts	$	2		$	4		$	(1	)	$	(2	)	Commodity contracts
Gas Contracts	(9		)	(9		)	10			8			Commodity contracts
Power Contracts	2			(11		)	(3		)	10			Commodity contracts
Interest Rate Risk	(233		)	(283		)	246			304			Long-term debt
Foreign Currency Exchange Risk	—			7			—			—			Forward contracts
Discount Rates	—			—			—			—			Commodity contracts

For further discussion of market risk, see Note 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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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 (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2012, which is the end of the period covered by this report. Based on this evaluation, the Company’s CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.


(b)	Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2012 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

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

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company has agreed to a Consent Order with the EPA to settle these historic air and water issues pursuant to which the Company will pay a fine of $1.75 million.

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. 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.

In July 2009, DTE Energy received a NOV/FOV from the EPA alleging, among other things, that five of Detroit Edison's power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant.

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In August 2010, the United States Department of Justice, at the request of EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit. Briefs have been filed with the Court of Appeals. A decision by the Court of Appeals is not expected until late 2012.

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

In October 2010, the Company received a Notice of Violation from the Michigan Department of Natural Resources (MDNRE) alleging that the Michigan coke battery facility violated the visible emission readings and quench water sampling requirements under applicable National Emissions Standards for Hazardous Air Pollutants regulations. This Notice of Violation resulted from the Company self reporting to the MDNRE and the EPA questionable activities by an employee of a contractor hired by the Company to perform visible emissions readings and quench water sampling. The information provided by the contractor was used by the Company in filing certain reports with the MDNRE and the EPA. The Company has ceased using the contractor for these activities, has retained a new certified contractor to perform the required activities and implemented standard operating procedures designed to prevent a reoccurrence of such a situation. At this time, the Company cannot predict the outcome or financial impact of this issue.

In December 2010, the Company received a Notice of Violation from the Detroit Water and Sewerage Department (DWSD) alleging that effluent discharges from the Michigan coke battery facility violated the City of Detroit Ordinance, the General Pre-Treatment Standards and the terms of a Consent Judgment entered between the Company and the DWSD with respect to the Michigan coke battery facility in March 2009. The Company has settled similar alleged violations with respect to the Michigan coke battery facility with the DWSD in the past. The Company has installed a biological waste water treatment plant at the Michigan coke battery facility in accordance with the Consent Judgment that is designed to meet the effluent limitations and is in the process of optimizing plant performance to minimize any future excursions of the Ordinance and the General Pre-Treatment Standards. The DWSD has demanded payment of $176,000 in penalties in connection with the alleged violations. The Company is actively pursuing a settlement with DWSD, but we cannot predict the outcome or financial impact of this matter.

In August 2011, Allegheny County Health Department (ACHD) issued an Enforcement Order alleging 114 incidents of fugitive pushing emissions at the coke battery facility in Pennsylvania. The Company has entered into a Consent Order with ACHD to settle this Enforcement Order pursuant to which the Company paid a fine of $100,000. The Company is completing a maintenance program designed to minimize future fugitive pushing emissions from the coke battery facility.

For additional discussion on legal matters, see Notes 6 and 11 of the Notes to Consolidated Financial Statements.

Item 1A. — Risk Factors

There are various risks associated with the operations of DTE Energy's utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we provided a brief explanation of the more significant risks associated with our businesses in Part 1, Item 1A. Risk Factors in the Company's 2011 Form 10-K. Although we have tried to identify and discuss key risk factors, others could emerge in the future.

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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 our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act for the quarter ended June 30, 2012:



	Number of Shares Purchased (a)	Average Price Paid per Share (a)		Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Average Price Paid per Share	Maximum Dollar Value that May Yet Be Purchased Under the Plans or Programs
04/01/2012 — 04/30/2012	101,299	$	56.27	—	—	—
05/01/2012 — 05/31/2012	880	55.74		—	—	—
06/01/2012 — 06/30/2012	25,052	57.54		—	—	—
Total	127,231			—

_____________________________


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

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Item 6. — Exhibits



		(i) Exhibits incorporated herein by reference:
4-274		Supplemental Indenture, dated as of June 20, 2012, to Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-279 to Detroit Edison's Form 10-Q for the quarter ended June 30, 2012). (2012 Series A and B).

10-81		Conformed Amended and Restated DTE Energy Company 2006 Long-Term Incentive Plan (as Amended and Restated effective as of May 6, 2010 as Amended effective May 3, 2012) (Exhibit A to DTE Energy's Definitive Proxy Statement dated March 15, 2012).

		(ii) Exhibits filed herewith:

12-51		Computation of Ratio of Earnings to Fixed Charges.

31-75		Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report.

31-76		Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Database

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase



		(iii) Exhibits furnished herewith:

32-75		Chief Executive Officer Section 906 Form 10-Q Certification

32-76		Chief Financial Officer Section 906 Form 10-Q Certification

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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 27, 2012	/s/ PETER B. OLEKSIAK
		Peter B. Oleksiak
		Vice President and Controller and Chief Accounting Officer

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