Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE OVERVIEW

DTE Energy is a diversified energy company with 2011 operating revenues of approximately $8.9 billion and approximately $26 billion in assets. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

The following table summarizes our financial results:

	2011		2010		2009
	(In millions, except per share amounts)
Net income attributable to DTE Energy Company	$	711	$	630	$	532
Diluted earnings per common share	$	4.18	$	3.74	$	3.24

The increase in 2011 Net income attributable to DTE Energy as compared to 2010 was driven by higher earnings in Energy Trading, partially offset by lower earnings in the Electric and Gas Utilities and in the Power and Industrial Projects segment. The 2011 increase is also due to an income tax benefit of $87 million in the Corporate and Other segment related to the enactment of the MCIT in the second quarter of 2011. The increase in 2010 Net income attributable to DTE Energy as compared to 2009 was primarily due to improved results in the Electric and Gas Utilities and in the Power and Industrial Projects segment, partially offset by lower earnings in Energy Trading.

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

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. Detroit Edison and MichCon both plan to seek regulatory approval in general rate case filings to include these capital expenditures within our regulatory rate base consistent with prior general rate case filing treatment. Detroit Edison is 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. See Note 2 of the Notes to Consolidated Financial Statements.

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. The Company estimates Detroit Edison will make capital expenditures of approximately $255 million in 2012 and up to approximately $1.9 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. EPA regulation of greenhouse gases (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 19 of the Notes to the Consolidated Financial Statements and Items 1. and 2. Business and Properties 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.

RESULTS OF OPERATIONS

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

	2011			2010			2009
	(In millions)
Net Income Attributable to DTE Energy by Segment:
Electric Utility	$	434		$	441		$	376
Gas Utility	110			127			80
Gas Storage and Pipelines	57			51			49
Unconventional Gas Production	(6		)	(11		)	(9		)
Power and Industrial Projects	38			85			31
Energy Trading	52			6			75
Corporate and Other	26			(69		)	(70		)
Net Income Attributable to DTE Energy Company	$	711		$	630		$	532

ELECTRIC UTILITY

Our Electric Utility segment consists principally of Detroit Edison.

Electric Utility results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	5,154		$	4,993		$	4,714
Fuel and Purchased Power	1,716			1,580			1,491
Gross Margin	3,438			3,413			3,223
Operation and Maintenance	1,370			1,305			1,277
Depreciation and Amortization	818			849			844
Taxes Other Than Income	240			237			205
Asset (Gains) Losses, Reserves and Impairments, Net	13			(6		)	(2		)
Operating Income	997			1,028			899
Other (Income) and Deductions	298			317			295
Income Tax Expense	265			270			228
Net Income Attributable to DTE Energy Company	$	434		$	441		$	376
Operating Income as a Percent of Operating Revenues	19		%	21		%	19		%

Gross margin increased $25 million in 2011 and increased $190 million in 2010. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

	2011			2010
	(In millions)
Rate case and Choice Incentive mechanism, net of Revenue Decoupling mechanism and sales volume	$	29		$	84
Restoration tracker	27			35
Securitization bond and tax surcharge	(39		)	40
Low Income Energy Efficiency Fund revenue deferral	(23		)	—
Energy optimization performance incentive	17			—
Regulatory mechanisms and other	14			31
Increase in gross margin	$	25		$	190

	2011	2010	2009
	(In thousands of MWh)
Electric Sales
Residential	15,907	15,726	14,625
Commercial	16,779	16,570	18,200
Industrial	9,739	10,195	9,922
Other	3,136	3,210	3,229
	45,561	45,701	45,976
Interconnection sales (1)	3,512	4,876	5,156
Total Electric Sales	49,073	50,577	51,132
Electric Deliveries
Retail and Wholesale	45,561	45,701	45,976
Electric Customer Choice, including self generators	5,445	5,005	1,477
Total Electric Sales and Deliveries	51,006	50,706	47,453

______________________________

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

	2011					2010					2009
	(In thousands of MWh)
Power Generated and Purchased
Power Plant Generation
Fossil	35,502			68	%	39,433			73	%	40,595			74	%
Nuclear	8,910			17		7,738			14		7,406			14
	44,412			85		47,171			87		48,001			88
Purchased Power	8,028			15		6,638			13		6,495			12
System Output	52,440			100	%	53,809			100	%	54,496			100	%
Less Line Loss and Internal Use	(3,367		)			(3,232		)			(3,364		)
Net System Output	49,073					50,577					51,132
Average Unit Cost ($/MWh)
Generation (1)	$	22.67				$	18.94				$	18.20
Purchased Power	$	42.78				$	42.38				$	37.74
Overall Average Unit Cost	$	25.75				$	21.83				$	20.53

_______________________________________

(1)Represents fuel costs associated with power plants.

Operation and maintenance expense increased $65 million in 2011 and increased $28 million in 2010. The increase in 2011 is primarily due to higher restoration and line clearance expenses of $41 million, higher generation maintenance and outage expenses of $25 million, higher energy optimization and renewable energy expenses of $19 million, higher employee benefit expense of $9 million, partially offset by reduced contributions of $23 million to the Low Income Energy Efficiency Fund due to a court order, and reduced uncollectible expenses of $7 million. The increase in 2010 is primarily due to higher restoration and line clearance expenses of $40 million, higher energy optimization and renewable energy expenses of $18 million, higher legal expenses of $15 million, partially offset by reduced uncollectible expenses of $20 million, lower generation expenses of $18 million and lower employee benefit-related expenses of $6 million.

Depreciation and amortization expense decreased $31 million in 2011 due primarily to reduced amortization of regulatory assets, partially offset by expense related to higher depreciable base. Depreciation and amortization expense was $5 million higher in 2010 due primarily to expense related to higher depreciable base and increased amortization of regulatory assets.

Taxes other than income were higher by $32 million in 2010 due primarily to a $30 million reduction in property tax expense in 2009 due to refunds received in settlement of appeals of assessments for prior years.

Asset (gains) and losses, reserves and impairments, net increased $19 million in 2011 principally attributable to an 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 revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. See Note 8 of the Notes to the Consolidated Financial Statements.

Outlook - The base rate and rehearing orders approved by the MPSC in fourth quarter 2011 provide for an annual revenue increase of $188 million and an authorized return on equity of 10.5%. The base rate order terminated Detroit Edison's Restoration, Line Clearance and Uncollectible Expense tracking mechanisms. Termination of these trackers may result in increased volatility in Detroit Edison's results due to weather, the number of storms and uncollectible accounts receivable. The Choice Incentive Mechanism was also terminated in the base rate order. Base rates included electric Customer Choice sales at the capped 10 percent level. See Note 11 of Notes to the Consolidated Financial Statements for further discussion of the rate orders received by Detroit Edison.

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.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	1,505		$	1,648		$	1,788
Cost of Gas	744			870			1,057
Gross Margin	761			778			731
Operation and Maintenance	394			378			415
Depreciation and Amortization	89			92			107
Taxes Other Than Income	54			55			49
Asset (Gains) and Losses, Net	—			—			(18		)
Operating Income	224			253			178
Other (Income) and Deductions	54			59			59
Income Tax Expense	60			67			39
Net Income Attributable to DTE Energy Company	$	110		$	127		$	80
Operating Income as a Percent of Operating Revenues	15		%	15		%	10		%

Gross margin decreased $17 million in 2011 and increased $47 million in 2010. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

	2011			2010
	(In millions)
Uncollectible tracking mechanism	$	(27	)	$	(43	)
2010 self-implementation and rate order	(4		)	125
Revenue decoupling mechanism	5			—
Energy optimization performance incentive	7			—
Midstream storage and transportation revenues	(12		)	(20		)
Subsidiaries transferred to Gas Storage and Pipelines segment	(17		)	—
Weather	25			(23		)
Lost and stolen gas	—			13
Other	6			(5		)
Increase (decrease) in gross margin	$	(17	)	$	47

	2011	2010	2009
Gas Markets (in Bcf)
Gas sales	123	118	137
End user transportation	141	140	124
	264	258	261
Intermediate transportation	273	391	463
	537	649	724

Operation and maintenance expense increased $16 million in 2011 and decreased $37 million in 2010. The increase in 2011 is primarily due to the 2010 deferral of $32 million of previously expensed CTA restructuring expenses and increased energy optimization expenses of $10 million, partially offset by reduced uncollectible expenses of $13 million, reduced expenses for subsidiaries transferred to Gas Storage and Pipelines segment of $6 million, lower customer service expenses of $5 million, and lower gas operations expenses of $4 million. The decrease in 2010 is primarily due to reduced uncollectible

expenses of $35 million and the deferral of $32 million of previously expensed CTA restructuring expenses, partially offset by higher maintenance expenses of $11 million, increased energy optimization expenses of $9 million, higher employee benefit-related expenses of $3 million and contributions of $3 million to the Low Income Energy Efficiency Fund.

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. We plan to file a base rate case in the second quarter 2012 and expect to self-implement new rates in the fourth quarter 2012 at the beginning of the heating season. Unfavorable economic trends have resulted in a decrease in the number of customers in our service territory, increased customer conservation and continued high levels of theft and uncollectible accounts receivable. The MPSC has provided for an uncollectible expense tracking mechanism which assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility in the future. Looking forward, additional factors may impact earnings such as infrastructure improvement capital programs, the outcome of future regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity, minimize lost and stolen gas, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

GAS STORAGE AND PIPELINES

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

Gas Storage and Pipelines results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	91		$	83		$	82
Operation and Maintenance	16			14			15
Depreciation and Amortization	6			5			5
Taxes Other Than Income	3			2			2
Operating Income	66			62			60
Other (Income) and Deductions	(28		)	(25		)	(23		)
Income Tax Expense	35			32			33
Net Income	59			55			50
Noncontrolling interest	2			4			1
Net Income Attributable to DTE Energy	$	57		$	51		$	49

Net income attributable to DTE Energy increased $6 million and $2 million in 2011 and 2010, respectively. The 2011 increase was primarily driven by earnings from subsidiaries that were transferred from Gas Utility, increased earnings from our pipeline equity investments, and a settlement for customer gas treating services performed in prior years. The 2010 increase was driven by higher gas storage revenues and lower project development costs.

Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. Millennium Pipeline has secured customers for its Phase 1 & 2 expansions which are scheduled to be in-service in the fourth quarter of 2012 and the fourth quarter of 2013, respectively. Millennium's total capacity with the Phase 1 & 2 expansion will increase from 525,000 dth/d to over 800,000 dth/d. In addition, we have executed an agreement with Southwestern Energy Services Company to support our Bluestone lateral and gathering system. Bluestone is a 40 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow 250,000 dth/d to both Millennium Pipeline and Tennessee Pipeline and is scheduled to be in service in 2012. We plan 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 in northern Texas.

Unconventional Gas Production results are discussed below:

	2011			2010			2009
	(In millions)
Operating Revenues	$	39		$	32		$	31
Operation and Maintenance	21			16			15
Depreciation, Depletion and Amortization	18			15			16
Taxes Other Than Income	3			2			1
Asset (Gains) and Losses, Net	—			10			6
Operating Income (Loss)	(3		)	(11		)	(7		)
Other (Income) and Deductions	6			6			6
Income Tax Benefit	(3		)	(6		)	(4		)
Net Income (Loss) Attributable to DTE Energy Company	$	(6	)	$	(11	)	$	(9	)

Unconventional Gas Production results were impacted by the impairment of expired or expiring leasehold positions in 2010 and 2009. Revenues and expenses increased in 2011 and 2010 as a result of new wells on line, increased liquids prices and higher crude oil production.

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 this liquids play which is expected to add value to our asset base. We expect total capital investment of $30 - 35 million to drill approximately 30 new wells and continue to acquire select acreage and achieve production of approximately 6 - 7 Bcfe, compared with 5 Bcfe in 2011. The majority of the drilling activity is expected to occur in the first half of 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:

	2011			2010			2009
	(In millions)
Operating Revenues	$	1,129		$	1,144		$	661
Operation and Maintenance	1,025			978			593
Depreciation and Amortization	60			60			40
Taxes other than Income	10			14			9
Asset (Gains) and Losses, Reserves and Impairments, Net	(12		)	(14		)	(6		)
Operating Income	46			106			25
Other (Income) and Deductions	(10		)	13			(1		)
Income Taxes
Expense	17			36			5
Production Tax Credits	(6		)	(33		)	(12		)
	11			3			(7		)
Net Income	45			90			33
Noncontrolling interest	7			5			2
Net Income Attributable to DTE Energy Company	$	38		$	85		$	31

VIEs — As discussed in Note 1 of Notes to the Consolidated Financial Statements, effective January 1, 2010, we adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, began consolidating five entities. Since these entities were previously accounted for under the equity method, the VIE consolidation had no impact on Net Income Attributable to DTE Energy. As a result of the consolidation of these VIEs, Operating Revenues and Operation and Maintenance expense increased $174 million and $122 million, respectively, in 2010.

Operating revenues decreased $15 million in 2011 and increased $309 million in 2010, net of VIE adjustments. The 2011 decrease is primarily due to $166 million of lower coal transportation and marketing services related to an expired rail transportation contract at significantly below market rates, $21 million of lower volumes associated with the coal blending business and a $20 million decrease from the sale of our rail services business in 2010, partially offset by a $92 million increase related to reduced emissions fuels projects, $74 million increase in coke demand and pricing, and a $26 million increase in new on-site energy services projects. The 2010 increase is attributed primarily to $172 million of higher coke sales and a $156 million increase in on-site services, partially offset by a $18 million decrease in coal trading and transportation services.

Operation and maintenance expense increased $47 million in 2011 and increased $263 million in 2010, net of VIE adjustments. The 2011 increase is due primarily to a $103 million increase in coal costs, a $93 million increase related to reduced emission fuels projects, and a $25 million increase in new on-site energy services projects, partially offset by $127 million lower coal transportation and marketing services related to the expired rail transportation contract, $19 million decrease from the sale of our rail services business in 2010, $17 million lower volumes primarily associated with the coal blending business and $11 million of lower coke battery operating costs. The 2010 increase is due primarily to $118 million of higher coke production and a $154 million increase in on-site services, partially offset by $10 million of lower coal trading and transportation services.

Asset (Gains) Losses decreased by $2 million in 2011 and increased by $8 million in 2010. The 2011 decrease was due to an asset impairment related to our landfill gas recovery business of $11 million, partially offset by installment gains of $9 million from the sale of a coke battery. The 2010 increase is due primarily to the sale of DTE Rail Services and an increase in installment gains from the sale of a coke battery.

Other (income) and deductions were higher by $23 million in 2011 and lower by $14 million in 2010. The increase in 2011 was due primarily to the production of refined coal from our reduced emissions fuels projects giving rise to tax credits which the Company has sold to third parties and gains on the extinguishment of debt related to our landfill gas recovery business. The decrease in 2010 was due primarily to lower equity earnings in various projects and higher intercompany interest associated with project investment.

Production tax credits decreased by $27 million in 2011 due primarily to the expiration of steel industry fuels credits as of December 31, 2010, partially offset by tax credits earned from reduced emission fuel projects. The increase of $21 million in 2010 was due primarily to a full year of steel industry fuels tax credits.

Outlook — The Company has constructed and placed in service nine reduced emission fuel facilities. The Company has sold a membership interest in two of these facilities that are located at the Detroit Edison sites. Additionally, the Company has constructed two facilities located at third party owned coal-fired power plants. 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. The executed and planned sales of membership interests in the reduced emission fuel facilities represent, in substance, the sale of production tax credits. The proceeds from these sales are expected to be received by the Company on an installment basis, and the Company will recognize the related income as production tax credits are generated by the respective facilities.

We expect sustained 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. Environmental and economic trends are creating growth opportunities for renewable power. The increasing number of states with renewable portfolio standards and energy efficiency mandates provides investment opportunity in waste-wood power generation. In addition to the four facilities that will be in operation in 2012, we are converting an additional facility to be placed in service in 2013. We will continue to look for additional investment opportunities and other energy projects at favorable prices.

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

ENERGY TRADING

Energy Trading focuses on physical and financial power 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, and the supply or purchase of renewable energy credits to various utilities which may include the management of associated storage and transportation contracts on the customers’ behalf.

Energy Trading results are discussed below:

	2011		2010		2009
	(In millions)
Operating Revenues	$	1,276	$	875	$	804
Fuel, Purchased Power and Gas	1,112		786		603
Gross Margin	164		89		201
Operation and Maintenance	63		59		71
Depreciation and Amortization	3		5		5
Taxes Other Than Income	3		2		3
Operating Income	95		23		122
Other (Income) and Deductions	9		12		10
Income Tax Expense	34		5		37
Net Income Attributable to DTE Energy Company	$	52	$	6	$	75

Gross margin increased $75 million in 2011 and decreased $112 million in 2010. The overall increase in gross margin in 2011 was the result of improved economic performance, coupled with the absence of prior year timing losses. We experienced timing-related earnings volatility based on market movement related to derivative contracts.

The increase in 2011 represents a $25 million increase in realized margins and $50 million increase in unrealized margins. The $25 million increase in realized margins is due to $73 million of favorable results, primarily in our power and gas trading and power full requirements strategies, offset by $48 million of unfavorable results, primarily in our power origination, gas structured and gas full requirements strategies. The $50 million increase in unrealized margins is due to $63 million of favorable results, primarily in our power full requirements, gas structured and gas trading strategies, offset by $13 million of unfavorable results, primarily in our power transmission strategy.

The decrease in 2010 represents a $78 million decrease in realized margins and $34 million decrease in unrealized margins. The $78 million decrease in realized margins is due to $108 million of unfavorable results, primarily in our power and gas trading and gas full requirements strategies, offset by $30 million of favorable results, primarily in our power full requirements and power origination strategies. The $34 million decrease in unrealized margins is due to $56 million of unfavorable results, primarily in our power trading strategy and the absence of prior year timing-related gains related to our gas transportation strategy. These decreases were offset by $22 million of favorable results, primarily due to timing-related gains in our gas full requirements strategy.

Operation and maintenance expense increased $4 million in 2011 and decreased $12 million in 2010. The 2011 increase was primarily due to higher incentive costs and the 2010 decrease was primarily due to lower incentive costs, both of which were impacted by economic performance.

Income tax provision increased $29 million in 2011, due to higher pretax income. Income taxes decreased $32 million in 2010, due to lower pretax income, partially offset by $10 million of favorable tax-related adjustments in 2009 resulting from the settlement of federal income tax audits.

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, and the supply or purchase of renewable energy credits to various utilities and producers which may include the management of associated storage and transportation contracts on the customers' behalf under FERC Asset Management Arrangements. 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 also the “Fair Value” section that follows.

CORPORATE AND OTHER

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

The 2011 net income of $26 million was an improvement of $95 million from the 2010 net loss of $69 million. The improvement resulted primarily from an income tax benefit of $87 million related to the enactment of the MCIT in the second quarter of 2011 and lower interest costs. See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this report.

The 2010 net loss of $69 million was an improvement of $1 million from the 2009 net loss of $70 million. The net $1 million improvement was a result of the 2009 donation to the DTE Energy Foundation of $10 million and lower impairments of investments of $3 million, partially offset by higher state and local taxes of $3 million, higher tax related interest of $5 million and increased financing costs of $5 million.

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. 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.

	2011			2010			2009
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	720		$	639		$	535
Depreciation, depletion and amortization	995			1,027			1,020
Deferred income taxes	220			457			205
Asset (gains) and losses, reserves and impairments, net	(21		)	(5		)	(10		)
Working capital and other	94			(293		)	69
	2,008			1,825			1,819
Investing activities:
Plant and equipment expenditures — utility	(1,382		)	(1,011		)	(960		)
Plant and equipment expenditures — non-utility	(102		)	(88		)	(75		)
Proceeds from sale of assets	18			56			83
Restricted cash and other investments	(94		)	(183		)	(112		)
	(1,560		)	(1,226		)	(1,064		)
Financing activities:
Issuance of long-term debt	1,179			614			427
Redemption of long-term debt	(1,455		)	(663		)	(486		)
Short-term borrowings, net	269			(177		)	(417		)
Issuance of common stock	—			36			35
Repurchase of common stock	(18		)	—			—
Dividends on common stock and other	(420		)	(396		)	(348		)
	(445		)	(586		)	(789		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	3		$	13		$	(34	)

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 totaling $2 billion in 2011 was $183 million higher than the comparable 2010 period. The operating cash flow comparison primarily reflects cash generated from working capital items, partially offset by lower net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred income taxes and gains on sales of assets).

Cash from operations totaling $1.8 billion in 2010, was consistent with the comparable 2009 period. The operating cash flow comparison primarily reflects higher net income after adjusting for non-cash and non-operating items, offset by cash used for 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.

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 higher in both 2011 and 2010 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 $445 million in 2011, compared to net cash used for financing activities of approximately $586 million for the same period in 2010. The change was primarily attributable to increased short-term borrowings and long-term debt issuances, partially offset by increased long-term debt redemptions.

Net cash used for financing activities was $586 million in 2010, compared to net cash used for financing activities of approximately $789 million for the same period in 2009. The change was primarily attributable to decreased payments for short-term borrowings. Increases in issuances of long-term debt were offset by increased long-term debt redemptions.

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.

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

We have approximately $500 million in long-term debt maturing in the next twelve months. Most of these maturities relate to Securitization and other Detroit Edison issues. The repayment of the principal amount of the Securitization debt is funded through a surcharge payable by Detroit Edison’s electric customers. The repayment of the other Detroit Edison debt is expected to be refinanced with long-term debt.

In October 2011, the Company completed an early renewal of its $1.0 billion and $800 million syndicated unsecured revolving credit facilities before their scheduled expiration in August 2012 and August 2013, respectively. The new $1.8 billion five-year facility will expire in October 2016 and has covenants similar to the prior facilities. DTE Energy has approximately $1.4 billion of available liquidity at December 31, 2011.

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

At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $240 million contribution to the 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 VEBA trusts in 2012.

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 $120 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.

See Notes 11, 12, 15, 17, and 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Contractual Obligations

The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2011:

	Total		2012		2013-2014		2015-2016		2017 and Beyond
	(In millions)
Long-term debt:
Mortgage bonds, notes and other	$	6,770	$	355	$	1,329	$	836	$	4,250
Securitization bonds	643		164		374		105		—
Junior subordinated debentures	280		—		—		—		280
Capital lease obligations	35		9		16		10		—
Interest	5,507		423		740		574		3,770
Operating leases	195		37		53		38		67
Electric, gas, fuel, transportation and storage purchase obligations (1)	5,080		2,112		1,920		333		715
Other long-term obligations (2)(3)(4)	235		164		33		13		25
Total obligations	$	18,745	$	3,264	$	4,465	$	1,909	$	9,107

_______________________________________

(1)Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.

(2)Includes liabilities for unrecognized tax benefits of $48 million.

(3)Excludes other long-term liabilities of $184 million not directly derived from contracts or other agreements.

(4)At December 31, 2011, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Capital Resources and Liquidity and Critical Accounting Estimates sections of MD&A and in Note 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. The Company’s credit ratings affect our cost of capital and other terms of financing as well as our ability to access the credit and commercial paper markets. Management believes that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.

As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the senior unsecured debt rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the senior unsecured debt rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if DTE Energy is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. A downgrade below investment grade could potentially increase the borrowing costs of DTE Energy and its subsidiaries and may limit access to the capital markets. The impact of a downgrade will not affect our ability to comply with our existing debt covenants. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews.

In January 2011, Fitch Ratings revised the rating outlook for Detroit Edison from stable to positive due to improvement in its credit protection measures as a result of supportive regulatory policies in Michigan. In January 2012, due to several factors including improved and sustained earnings and an overall constructive regulatory environment, Fitch Ratings raised Detroit Edison's senior secured debt rating from 'A-' to 'A' and raised MichCon's senior secured debt rating from 'BBB+' to 'A-'. At the same time, Fitch Ratings revised the rating outlook for MichCon from stable to positive.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles require that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of these accounting policies can be found in the Notes to Consolidated Financial Statements in Item 8 of this Report.

Regulation

A significant portion of our business is subject to regulation. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

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 proposed by parties involved in the reconciliation proceeding 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.

In addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the pilot RDM effective October 2011 as ordered by the MPSC, 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. In addition, similar to the initial reconciliation case, there could be 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 the rehearing request and alternative calculation methodologies, 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 December 31, 2011. An MPSC order

on the initial filing is expected in the first half of 2012. Detroit Edison is required to file an application with the MPSC for approval of its RDM reconciliation for the 2011 reconciliation period by May 2012. A newly designed RDM will be in effect beginning April 2012.

See Note 11 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Derivatives and Hedging Activities

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. Substantially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.

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 and liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. Management makes certain assumptions it believes that market participants would use in pricing assets and liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and our counterparties is incorporated in the valuation of the assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 2011 and 2010. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. Actual cash returns realized on our derivatives may be different from the results we estimate using models. As fair value calculations are estimates based largely on commodity prices, we perform sensitivity analysis on the fair values of our forward contracts. See sensitivity analysis in Item 7A. Quantitative and Qualitative Disclosures About Market Risk. See also the Fair Value section, herein. See Notes 3 and 4 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based on historical losses and management's assessment of existing economic conditions, customer trends, and other factors. The allowance for doubtful accounts for our two utilities is calculated using the aging approach that utilizes rates developed in reserve studies and applies these factors to past due receivable balances. As a result of the reduction in past due receivables in 2011 and further refinements to our reserve studies, our allowance for doubtful accounts decreased significantly from the 2010 balance. We believe the allowance for doubtful accounts is based on reasonable estimates. As part of the 2005 gas rate order for MichCon, the MPSC provided for the establishment of an uncollectible expense tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. The MPSC provided for a similar tracking mechanism for Detroit Edison in its rate order received January 2010, however it was terminated effective with the electric rate order in October 2011.

Asset Impairments

Goodwill

Certain of our reporting units have goodwill or allocated goodwill resulting from purchase business combinations. We perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

For Step 1 of the test, we estimate the reporting unit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. We also employ market-based valuation techniques to test the reasonableness of the indications of value for the reporting units determined under the cash flow technique.

We performed our annual impairment test as of October 1, 2011 and determined that no impairment existed. We also compared the aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to an acquisition control premium (the price in excess of a stock's market price that investors typically pay to gain control of an entity). The results of the test and key estimates that were incorporated are as follows.

As of October 1, 2011 Valuation Date

Reporting Unit	Goodwill		Fair Value Reduction % (a)		Discount Rate		Terminal Multiple (b)	Valuation Methodology (c)
	($ in millions)
Electric Utility	$	1,208	23	%	7	%	8.0x	DCF, assuming stock sale
Gas Utility	745		16	%	7	%	10.0x	DCF, assuming stock sale
Power and Industrial Projects	26		71	%	10	%	8.0x	DCF, assuming asset sale (d)
Gas Storage and Pipelines	22		75	%	9	%	10.0x	DCF, assuming asset sale
Energy Trading	17		50	%	15	%	n/a	Blended DCF, economic value of trading portfolio
Unconventional Gas Production	2		55	%	11	%	n/a	Blended DCF, transaction multiples
	$	2,020

_______________________________________

(a)	Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value, including goodwill.
(b)	Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA).
(c)	Discounted cash flows (DCF) incorporated 2012-2016 projected cash flows plus a calculated terminal value.
(d)	Asset sales were assumed except for Power and Industrial Projects' reduced emissions fuels projects, which assumed stock sales.

The Gas Utility reporting unit passed Step 1 of the impairment test, however further declines in market multiples, negative regulatory actions or other disruptions in cash flows for the Gas Utility reporting unit could result in an impairment charge in the foreseeable future. For example, at the current discount rate and holding all other variables constant, a 1.5x decrease in the terminal multiple would lower the fair value by approximately $423 million. At the lower fair value, the Gas Utility reporting unit would likely fail Step 1 of the test potentially resulting in a charge for impairment of goodwill following completion of the Step 2 analysis.

We perform an annual impairment test each October. In between annual tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

Long-Lived Assets

We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, condition of the asset, or plans to dispose of the asset before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. See Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Report.

Pension and Postretirement Costs

We sponsor defined benefit pension plans and postretirement benefit plans for eligible employees of the Company. The measurement of the plan obligations and cost of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. When determining the various assumptions that are required, we consider historical information as well as future expectations. The benefit costs are affected by, among other things, the actual rate of return on plan assets, the long-term expected return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the anticipated rate of increase of health care costs and the level of benefits provided to employees and retirees. Pension and postretirement benefit costs attributed to the segments are included with labor costs and ultimately allocated to projects within the segments, some of which are capitalized.

We had pension costs of $172 million in 2011, $112 million in 2010, and $58 million in 2009. Postretirement benefits costs were $122 million in 2011, $164 million in 2010 and $205 million in 2009. Pension and postretirement benefits costs for 2011 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.5% for pension plan assets and 8.75% for postretirement health and life plan assets. In developing our expected long-term rate of return assumptions, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity, bond and other markets. Our 2012 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment management of 47% in equity markets, 25% in fixed income markets, and 28% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we are lowering our long-term rate of return assumption for our pension plans and our postretirement health and life plans to 8.25% for 2012. We believe this rate is a reasonable assumption for the long-term rate of return on our plan assets for 2012 given our investment strategy. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

We calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. Current accounting rules provide that the MRV of plan assets can be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For our pension plans, we use a calculated value when determining the MRV of the pension plan assets and recognize changes in fair value over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recognized. Financial markets in 2011 contributed to our investment performance resulting in unrecognized net losses. As of December 31, 2011, we had $100 million of cumulative losses that remain to be recognized in the calculation of the MRV of pension assets. For our postretirement benefit plans, we use fair value when determining the MRV of postretirement benefit plan assets, therefore all investment losses and gains have been recognized in the calculation of MRV for these plans.

The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected pension plan and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis decreased to 5.0% at December 31, 2011 from 5.5% at December 31, 2010. We estimate that our 2012 total pension costs will approximate $215 million compared to $172 million in 2011 primarily due to a lower discount rate, lower expected return on assets and higher amortization of net actuarial losses, partially offset by 2012 contributions. Our 2012 postretirement benefit costs will approximate $155 million compared to $122 million in 2011 primarily due to a lower discount rate, lower expected return on plan assets, higher amortization of net actuarial losses and updated assumed long-term retiree medical inflation, partially offset by favorable retiree medical utilization. Our health care trend rate assumes 7.00% for 2012 through 2016, 6.50% in 2017, 6.00% in 2018, 5.50% in 2019 and 5.00% in 2020 and beyond. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. The MPSC approved the deferral of the non-capitalized portion of MichCon's negative pension expense. MichCon records a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.

Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 2011 pension costs by approximately $29 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2011 pension costs by approximately $7 million. Lowering the health care cost trend assumptions by one percentage point would have decreased our postretirement benefit service and interest costs for 2011 by approximately $24 million.

The value of our pension and postretirement benefit plan assets was $3.9 billion at December 31, 2011 and December 31, 2010. At December 31, 2011, our pension plans were underfunded by $1.3 billion and our other postretirement benefit plans were underfunded by $1.5 billion. The 2011 and 2010 funding levels were generally similar due to plan sponsor contributions

in 2011 and 2010, largely offset by the decreased discount rates.

Pension and postretirement costs and pension cash funding requirements may increase in future years without typical returns in the financial markets. We made contributions to our pension plans of $200 million in 2011 and $200 million in 2010. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making contributions to our pension plans of $240 million in 2012 and up to $1.1 billion over the next five years. We made postretirement benefit plan contributions of $111 million and $160 million in 2011 and 2010, respectively. We are required by orders issued by the MPSC to make postretirement benefit contributions at least equal to the amounts included in our utilities' base rates. As a result, we contributed $140 million to our postretirement plans in January 2012 and expect to make up to an additional $120 million contribution to our postretirement plans in 2012 and, subject to MPSC funding requirements, up to $855 million over the next five years. The planned contributions will be made in cash, DTE Energy common stock or a combination of cash and stock.

Effective in June 2011, we discontinued offering future Greater Michigan represented employees a defined benefit pension plan benefit. In its place, the Company will annually contribute an amount equivalent to four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan. Also, for future Greater Michigan represented employees after completion of one year of service, in lieu of offering post-employment health care and life insurance benefits, the Company will contribute an amount equivalent to an additional four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan, plus a one-time contribution of $1,400.

Effective January 1, 2012, we discontinued offering future non-represented employees a cash balance retirement plan benefit. In its place, the Company will annually contribute an amount equivalent to four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan. Also effective January 1, 2012, in lieu of offering future non-represented employees post-employment health care and life insurance benefits, the Company will allocate $4,000 per year to an account in a tax-exempt trust for each employee. The accumulated balance and earnings in an employee's account will vest when the employee has 10 years of service, regardless of age. These funds will be available to the employee to use for health care expenses after the employee leaves the Company.

See Note 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Legal Reserves

We are involved in various legal proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against us.

Insured and Uninsured Risks

Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage- $10 million, general liability- $7 million, workers’ compensation- $9 million, and auto liability-$7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2011, this IBNR liability was approximately $39 million.

Accounting for Tax Obligations

We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We also have non-income tax obligations related to property, sales and use and employment-related taxes and ongoing appeals related to these tax matters.

Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess

our ability to utilize tax attributes, including those in the form of carry-forwards, for which the benefits have already been reflected in the financial statements. We do not record valuation allowances for deferred tax assets related to capital losses that we believe will be realized in future periods. We believe the resulting tax reserve balances as of December 31, 2011 and December 31, 2010 are appropriately accounted. The ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material.

See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

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

The Company has established a fair value hierarchy 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 during 2011:

	Total
	(In millions)
MTM at December 31, 2010	$	(44	)
Reclassify to realized upon settlement	(37		)
Changes in fair value recorded to income	159
Amounts recorded to unrealized income	122
Changes in fair value recorded in regulatory liabilities	2
Change in collateral held by others	10
Option premiums paid (received) and other	(41		)
MTM at December 31, 2011	$	49

The table below shows the maturity of our MTM positions:

Source of Fair Value	2012			2013			2014		2015 and Beyond			Total Fair Value
	(In millions)
Level 1	$	(32	)	$	17		$	10	$	(5	)	$	(10	)
Level 2	(7		)	(34		)	1		—			(40		)
Level 3	29			9			5		1			44
Total MTM before collateral adjustments	$	(10	)	$	(8	)	$	16	$	(4	)	$	(6	)
Collateral adjustments												$	55
Total MTM at December 31, 2011												$	49

DTE - Dte Energy Company