EX-99.2

Exhibit 99.2

Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with 2008 operating revenues in excess of $9 billion and over $24 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:


	2008		2007		2006
	(In millions, except earnings per share)
Income from continuing operations, excluding noncontrolling interests	$	526	$	787	$	389
Diluted earnings per common share from continuing operations, excluding noncontrolling interests	$	3.22	$	4.61	$	2.18
Net income attributable to DTE Energy Company	$	546	$	971	$	433
Diluted earnings per common share	$	3.34	$	5.69	$	2.43

The decrease in 2008 from 2007 was primarily due to approximately $370 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $900 million ($580 million after-tax), partially offset by losses recognized on related hedges of $323 million ($210 million after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income during 2007. Net income in 2008 was also impacted by a gain of $128 million ($81 million after-tax) on the sale of a portion of the Barnett shale properties.

The items discussed below influenced our current financial performance and may affect future results:

	•		Impacts of national and regional economic conditions on utility operations;

	•		Effects of weather on utility operations;

	•		Collectibility of accounts receivable on utility operations;

	•		Impact of regulatory decisions on utility operations;

	•		Impact of legislation on utility operations;

	•		Fluctuations in market demand on coal supply;

	•		Challenges associated with nuclear fuel;

	•		Monetization of portions of our Unconventional Gas Production business;

	•		Discontinuance of planned monetization of a portion of our Power and Industrial Projects business;

	•		Results in our Energy Trading business;

	•		Discontinuance of the Synthetic Fuel business; and

	•		Required environmental and reliability-related capital investments.

UTILITY OPERATIONS

Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.

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

Impact of national and regional economic conditions on our utility operations — Revenues from our utility operations follow the economic cycles of the customers we serve. Our utilities provide services to the domestic automotive industry which is under considerable financial distress, exacerbating the decline in regional conditions. In 2008, Detroit Edison experienced a decline in sales in its service territory as compared to 2007. We expect this decline to continue in 2009. As discussed further below, deteriorating economic conditions impact our ability to collect amounts due from our customers of our electric and gas utilities and drive higher levels of lost and stolen natural gas at MichCon. In the face of the economic conditions, we are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength.

Effects of Weather on Utility Operations — Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. During the year ended December 31, 2008 we experienced colder weather than the year ended December 31, 2007.

Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure, resulting in power outages. Restoration and other costs associated with storm-related power outages lowered pre-tax earnings by $61 million in 2008, $68 million in 2007 and $46 million in 2006.

Collectibility of Accounts Receivable on Utility Operations — Both utilities continue to experience high levels of past due receivables, which is primarily attributable to economic conditions including high levels of unemployment and home foreclosures. High energy prices and a lack of adequate levels of assistance for low-income customers have also impacted our accounts receivable.

We have taken actions to manage the level of past due receivables, including customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers.

Our uncollectible accounts expense for the two utilities increased to $213 million in 2008 from $135 million in 2007 and from $123 million in 2006.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. The MPSC approved the 2005 annual reconciliation in December 2006, allowing MichCon to surcharge $11 million beginning in January 2007. The MPSC approved the 2006 annual reconciliation in December 2007, allowing MichCon to surcharge $33 million beginning in January 2008. In December 2008, MichCon received authorization to surcharge $34 million, including a $1 million uncollected balance from the 2005 surcharge, beginning in January 2009. We accrue interest income on the outstanding balances.

Impact of Regulatory Decisions on Utility Operations — On December 23, 2008, the MPSC issued an order in Detroit Edison’s February 20, 2008 updated rate case filing. The MPSC approved an annual revenue increase of $84 million effective January 14, 2009 or a 2.0% average increase in Detroit Edison’s annual revenue requirement for 2009. Included in the approved $84 million increase in revenues was a return on equity of 11% on an expected 49% equity and 51% debt capital structure.

Other key aspects of the MPSC order include the following:

•

In order to more accurately reflect the actual cost of providing service to business customers, the MPSC adopted an immediate 39% phase out of the residential rate subsidy, with the remaining amount to be eliminated in equal installments over the next five years, every October 1.

	•		Accepted Detroit Edison’s proposal to reinstate and modify the tracking mechanism on Electric Choice sales (CIM) with a base level of 1,561 GWh. The modified mechanism will not have a cap on the amount recoverable.

	•		Terminated the Pension Equalization Mechanism.

	•		Approved an annual reconciliation mechanism to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $110 million and $51 million, respectively.

	•		Approved Detroit Edison’s proposal to recover a return on $15 million in working capital associated with the preparation of an application for a new nuclear generation facility at its current Fermi 2 site.

The MPSC issued an order on August 31, 2006 approving a settlement agreement providing for an annualized rate reduction of $53 million for 2006 for Detroit Edison, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $76 million in 2007 and approximately $25 million during the period the rate reduction was in effect for 2008, as a result of this order. The revenue reduction was net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was approved by the MPSC that provides for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provides for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, have enabled 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $41 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon sold 0.75 Bcf of base gas in 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the base gas to GCR customers during the 2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of the 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income and not include the proceeds in the calculation of MichCon’s revenue requirements in future rate cases.

Impact of Legislation on Utility Operations — On September 18, 2008, the Michigan House of Representatives and Michigan Senate passed a package of bills to establish a comprehensive, sustainable, long-term energy plan for Michigan. The Governor of Michigan signed the bills on October 6, 2008.

The package of bills includes:

	•		2008 Public Act (PA) 286 that reforms Michigan’s utility regulatory framework, including the electric Customer Choice program,

	•		2008 PA 295 that establishes a renewable portfolio / energy optimization standard and provides a funding mechanism, and

	•		2008 PA 287 that provides for an income tax credit for the purchase of energy efficient appliances and a credit to offset a portion of the renewable charge.

2008 PA 286 makes the following changes in the regulatory framework for Michigan utilities.

•

Electric Customer Choice reform — The bill establishes a 10 percent limit on participation in the electric Customer Choice program. In general, customers representing 10 percent of a utility’s load may receive electric generation from an electric supplier that is not a utility. After that threshold is met, the remaining customers will remain on full, bundled utility service. As of December 31, 2008, approximately 3 percent of Detroit Edison’s load was on the electric Customer Choice program. The bill also allows continuation of prior MPSC policies for customers to return to full utility service.

	•		Cost-of-service based electric rates (deskewing) — The bill requires the MPSC to set rates based on cost-of-service for all customer classes, eliminating over a five-year period the current subsidy by businesses of residential customer rates. This provision does not change total revenue for Detroit Edison. It lowers rates for most commercial and industrial customers and increases rates for residential and certain other industrial customers to match the actual cost of service for each customer class. Rate changes will be phased in over five years, with a 2.5% annual cap on residential rate increases due to deskewing beginning January 1, 2009. Rates for schools and other qualified educational institutions will be set at their cost of service sooner.

	•		File and use ratemaking — The bill establishes a 12 month deadline for the MPSC to complete a rate case and allows a utility to self-implement rate changes six months after a rate filing, subject to certain limitations. If the final case order leads to lower rates than the utility had self-implemented, the utility will refund with interest, the difference. In addition, utility rate cases may be based on a forward test year. The bill also has provisions designed to help the MPSC obtain increased funding for additional staff.

	•		Certificate of Need process for major capital investments — The bill establishes a certificate of need process for capital projects costing more than $500 million. The process requires the MPSC to review for prudence, prior to construction, proposed investments in new generating assets, acquisitions of existing power plants, major upgrades of power plants, and long-term power purchase agreements. The bill increases the certainty for utilities to recover the cost of projects approved by the MPSC and provides for the utilities to recover interest expenses during construction.

	•		Merger & Acquisition approval — The bill grants the MPSC the authority to review and approve proposed utility mergers and acquisitions in Michigan and sets out evaluation criteria.

2008 PA 295 establishes renewable energy and energy optimization (energy efficiency, energy conservation or load management) programs in Michigan and provides for a separate funding surcharge to pay the cost of those programs. In accordance with the new law, the MPSC issued a temporary order on December 4, 2008 implementing this act. Within 90 days following the issuance of the temporary order, Detroit Edison is required to file a Renewable Portfolio Standard (RPS) plan with the MPSC. In addition, Detroit Edison and MichCon are required to file Energy Optimization plans with the MPSC.

Renewable Energy Standard

	•		The bill requires electric providers to source 10% of electricity sold to retail customers from renewable energy resources by 2015.

	•		Qualifying renewable energy resources include wind, biomass, solar, hydro, and geothermal, among others.

	•		Detroit Edison will be required to have a renewable energy capacity portfolio of 300MW by December 31, 2013 and 600MW by December 31, 2015.

	•		The MPSC will establish a per meter surcharge to fund the renewable energy requirements. The recovery mechanism starts prior to actual construction in order to smooth the rate impact for customers.

	•		The bill allows for the lowering of compliance if RPS costs exceed the surcharge/cost cap or if other specified factors adversely affect the availability of renewable energy.

	•		The bill specifies that a utility can build or have others build and later sell to the utility up to 50 percent of the generation required to meet the RPS. The other 50 percent would be contracted through power purchase agreements.

	•		The bill also provides for a net metering program to be established by MPSC order for on-site customer-owned renewable generation up to 1% of an electric utility’s load.

Energy Optimization Standard

	•		Requires utilities to create electric and natural gas energy optimization plans for each customer class and includes funding surcharges as well as the potential for incentives for exceeding performance goals.

	•		For electric sales, the program targets 0.3 percent annual savings in 2009, ramping up to 1 percent annual savings by 2012. Savings percentages are based on prior year retail sales.

	•		For natural gas sales, the targeted annual savings start at 0.1 percent in 2009 and ramp up to 0.75 percent by 2012.

	•		The MPSC will allow utilities to capitalize certain costs of their energy optimization program. The costs which can be capitalized include equipment, materials, installation costs and customer incentives.

	•		Incentives are potentially available for exceeding annual program targets. The financial incentive could be the lesser of 25% of the net cost reduction to our customers or 15% of total program spend, subject to MPSC approval.

	•		The bill would also allow a natural gas utility that spends at least 0.5 percent of its revenues on energy efficiency programs to implement a symmetrical decoupling true-up mechanism that adjusts for sales volumes that are above or below the level reflected in its gas distribution rates.

	•		By March 2016, the MPSC may suspend the program if it determines the program is no longer cost-effective.

Impact of Increased Market Demand on Coal Supply — Our generating fleet produces approximately 79% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in volatility and higher prices which are passed to our customers through the PSCR mechanism. The demand and price volatility have been dampened by the recent economic downturn, but are expected to increase as the economy improves. In addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal have resulted in decreasing coal output from the central Appalachian region. Furthermore, as a result of environmental regulation and declining eastern coal stocks, demand for cleaner burning western coal has increased.

Challenges Associated with Nuclear Fuel — We operate one nuclear facility (Fermi 2) that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold; this fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. We are a party in 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. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage and have begun work on an on-site dry cask storage facility.

NON-UTILITY OPERATIONS

We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. As part of a strategic review of our non-utility operations, we have taken various actions including the sale of certain non-utility businesses.

Gas Midstream

Gas Midstream owns partnership interests in two interstate transmission pipelines and two natural gas storage fields. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We also hold partnership interests in Millennium Pipeline Company which indirectly connects southern New York State to Upper Midwest/Canadian supply, while providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 87 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facilities are high deliverability storage fields having bi-directional interconnections with Vector Pipeline and MichCon providing our customers access to the

Chicago, Michigan, other Midwest and Ontario market centers. The pipeline business is expanding and building new pipeline capacity to serve markets in Northeast United States.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 62,395 (60,435 acres, net of interest of others). We continue to acquire select positions in active development areas in the Barnett shale to optimize our existing portfolio.

Monetization of Portions of our Unconventional Gas Production Business — In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 75 Bcfe of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale. The Company recognized a cumulative pre-tax gain of $128 million ($81 million after-tax) on the sale during 2008.

We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $96 million in the Barnett shale in 2008 and expect to invest approximately $25 million in 2009. During 2009, we expect to drill 15 to 25 new wells and achieve Barnett shale production of approximately 5-6 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.

As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of anticipated production from our reserves to secure an attractive investment return. As of December 31, 2008, we have a series of cash flow hedges for approximately 3.2 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.33 per Mcf.

Texas — Barnett Shale


	2008		2007		2006
Net Producing Wells
Held for sale		—		33		27
Held for use		155		120		83

Total		155		153		110
Production Volume (Bcfe)
Held for sale		—		4.7		2.8
Held for use		5.0		3.0		1.3

Total		5.0		7.7		4.1
Proved Reserves (Bcfe)(1)
Held for sale		—		75		60
Held for use		167		144		111

Total		167		219		171
Net Developed Acreage(1)
Held for sale		—		4,987		3,977
Held for use(2)		14,248		9,880		10,693

Total		14,248		14,867		14,670
Net Undeveloped Acreage(1)
Held for sale		—		5,809		6,164
Held for use(2)		46,187		38,066		27,613

Total		46,187		43,875		33,777
Capital Expenditures (in Millions)(3)
Held for sale	$	—	$	45	$	67
Held for use		96		95		61

Total	$	96	$	140	$	128
Future Undiscounted Net Cash Flows (in Millions)(4)
Held for sale	$	—	$	282	$	167
Held for use		324		521		305

Total	$	324	$	803	$	472
Average gas price (per Mcf)	$	8.69	$	6.29	$	5.66


(1)		Due to the impairment of acreage and wells in the southern expansion area of the Barnett shale during 2007, the proved reserves and acreage numbers above do not include the southern area. Total net acreage related to impaired leases in the southern expansion area was 23,659 acres and 32,083 acres for the years 2007 and 2006, respectively. In 2008, an impairment was recorded on approximately 5,600 acres within the western expansion of the Barnett Shale. Impaired acreage and wells are not included in the table above.

(2)		Developed acreage for continuing operations shows a decrease from 2006 to 2007, which reflects the Company’s experience that spacing of wells in the Barnett shale has been reduced over the years. This reduced spacing estimate drives a shift from developed to undeveloped acreage counts. We continue to expand our total position in the western expansion area of the Barnett shale.

(3)		Excludes sold and impaired assets in southern expansion area of the Barnett shale.

(4)		Represents the standardized measure of undiscounted future net cash flows utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.

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 and marketing; and sell electricity from biomass-fired energy projects. This business segment provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries.

Services provided include pulverized coal, petroleum coke and metallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate one gas-fired peaking electric generating plant, two biomass-fired electric generating plants and operate one coal-fired power plant. A third biomass-fired electric generating plant is currently under development pending certain regulatory and management approvals with an expected in-service date of January 2010. This business segment also develops, owns and operates landfill gas recovery systems throughout the United States and produces metallurgical coke from three coke batteries. The production of coke from two of the coke batteries generates production tax credits. The business provides coal transportation — related services including fuel, transportation, storage, blending and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. This business segment performs coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users or for small power generation projects.

Discontinuance of Planned Monetization of our Power and Industrial Projects Business — During the third quarter of 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time. During 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, our work on this planned monetization was discontinued. As of June 30, 2008, the assets and liabilities of the Projects are no longer classified as held for sale.

Energy Trading

Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio and the optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in the recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.

Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipelines and certain storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are

marked-to-market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.

DISCONTINUED OPERATIONS

Synthetic Fuel

The Synthetic Fuel business was presented as a non-utility segment through the third quarter of 2007. Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. To optimize income and cash flow from synfuel operations, we sold interests in all nine of the facilities, representing 91% of the total production capacity. The synthetic fuel plants generated operating losses that were offset by production tax credits.

The value of a production tax credit was adjusted annually by an inflation factor and published annually by the IRS. The value of production tax credits for synthetic fuel was reduced when the Reference Price of a barrel of oil exceeded certain thresholds. The actual tax credit phase-out for 2007 was approximately 67%.

CAPITAL INVESTMENT

We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility segment currently expects to invest approximately $6 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects during the period of 2009 through 2013. Our gas utility segment currently expects to invest approximately $750 million to $800 million on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.

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:

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

	•		managing the growth of our utility asset base;

	•		enhancing our cost structure across all business segments;

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

	•		improving Electric and Gas Utility customer satisfaction; 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

Segments realigned — Beginning in the second quarter of 2008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment (now the Gas Midstream segment) to the Power and Industrial Projects segment due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. See Note 20 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report for further information on this realignment. The following sections provide a detailed discussion of the operating performance and future outlook of our segments.


	2008			2007			2006
	(In millions)
Net Income Attributable to DTE Energy Company by Segment:
Electric Utility	$	331		$	317		$	325
Gas Utility		85			70			50
Non-utility Operations:
Gas Midstream		38			34			28
Unconventional Gas Production(1)		84			(217	)		9
Power and Industrial Projects		40			49			(58	)
Energy Trading		42			32			96
Corporate & Other(1)		(94	)		502			(61	)
Income (Loss) from Continuing Operations:
Utility		416			387			375
Non-utility		204			(102	)		75
Corporate & Other		(94	)		502			(61	)

		526			787			389
Discontinued Operations		20			184			43
Cumulative Effect of Accounting Changes		—			—			1

Net Income Attributable to DTE Energy Company	$	546		$	971		$	433


(1)		2008 net income attributable to DTE Energy Company of the Unconventional Gas Production segment resulted principally from the gain on the sale of a portion of our Barnett shale properties. 2007 net loss attributable to DTE Energy Company resulted principally from the recognition of losses on hedge contracts associated with the Antrim sale transaction. 2007 net income attributable to DTE Energy Company of the Corporate & Other segment resulted principally from the gain recognized on the Antrim sale transaction. See Note 3 of the Notes to the Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Factors impacting income: Net income attributable to DTE Energy Company increased $14 million in 2008 and decreased $8 million in 2007. The 2008 increase was primarily due to lower expenses for operation and maintenance, depreciation and amortization, and taxes other than income, partly offset by lower gross margins and higher income tax expense. The 2007 decrease reflects higher operation and maintenance expenses, partially offset by higher gross margins and lower depreciation and amortization expenses.


	2008			2007			2006
	(In millions)
Operating Revenues	$	4,874		$	4,900		$	4,737
Fuel and Purchased Power		1,778			1,686			1,566

Gross Margin		3,096			3,214			3,171
Operation and Maintenance		1,322			1,422			1,336
Depreciation and Amortization		743			764			809
Taxes Other Than Income		232			277			252
Asset (Gains) Losses and Reserves, Net		(1	)		8			(6	)

Operating Income		800			743			780
Other (Income) and Deductions		283			277			294
Income Tax Provision		186			149			161

Net Income Attributable to DTE Energy Company	$	331		$	317		$	325

Operating Income as a Percent of Operating Revenues		16	%		15	%		16	%

Gross margin decreased $118 million during 2008 and increased $43 million in 2007. The 2008 decrease was due to the unfavorable impacts of weather and service territory performance and the absence of the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation. These decreases were partially offset by higher rates attributable to the April 2008 expiration of a rate reduction related to the MPSC show cause proceeding and higher margins due to customers returning from the electric Customer Choice program. The increase in 2007 was attributed to higher margins due to returning sales from electric Customer Choice, the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and weather related impacts, partially offset by lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding and the unfavorable impact of a September 2006 MPSC order related to the 2004 PSCR reconciliation. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.

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


Increase (Decrease) in Gross Margin Components Compared to Prior Year	2008			2007
	(In millions)
Weather-related impacts	$	(37	)	$	31
Return of customers from electric Customer Choice		35			43
Service territory performance		(100	)		28
Refundable pension cost		(30	)		—
April 2008 expiration of show cause rate decrease		46			—
Impact of 2006 MPSC show cause order		—			(64	)
Impact of 2005 MPSC PSCR reconciliation order		(38	)		38
Impact of 2004 MPSC PSCR reconciliation order		—			(39	)
Other, net		6			6

Increase (decrease) in gross margin	$	(118	)	$	43


Power Generated and Purchased	2008					2007					2006
	(In thousands of MWh)
Power Plant Generation
Fossil		41,254		71	%		42,359		72	%		39,686		70	%
Nuclear		9,613		17			8,314		14			7,477		13

		50,867		88			50,673		86			47,163		83
Purchased Power		6,877		12			8,422		14			9,861		17

System Output		57,744		100	%		59,095		100	%		57,024		100	%
Less Line Loss and Internal Use		(3,445	)				(3,391	)				(3,603	)

Net System Output		54,299					55,704					53,421

Average Unit Cost ($/MWh)
Generation(1)	$	17.93				$	15.83				$	15.61

Purchased Power	$	69.50				$	62.40				$	53.71

Overall Average Unit Cost	$	24.07				$	22.47				$	22.20


(1)		Represents fuel costs associated with power plants.


	2008		2007		2006
	(In thousands of MWh)
Electric Sales
Residential		15,492		16,147		15,769
Commercial		18,920		19,332		17,948
Industrial		13,086		13,338		13,235
Wholesale		2,825		2,902		2,826
Other		393		398		402

		50,716		52,117		50,180

Interconnection sales(1)		3,583		3,587		3,241

Total Electric Sales		54,299		55,704		53,421

Electric Deliveries
Retail and Wholesale		50,716		52,117		50,180
Electric Customer Choice		1,382		1,690		2,694
Electric Customer Choice — Self Generators(2)		75		549		909

Total Electric Sales and Deliveries		52,173		54,356		53,783


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

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

Operation and maintenance expense decreased $100 million in 2008 and increased $86 million in 2007. The decrease in 2008 was due primarily to lower information systems implementation costs of $60 million, lower benefit expense of $45 million and lower corporate support expenses of $29 million, partially offset by higher uncollectible expenses of $22 million. The increase in 2007 is primarily due to higher information systems implementation costs of $30 million, higher storm expenses of $22 million, increased uncollectible expense of $22 million and higher corporate support expenses of $20 million.

Depreciation and amortization expense decreased $21 million in 2008 and $45 million in 2007. The 2008 decrease was due primarily to decreased amortization of regulatory assets. The 2007 decrease was due primarily to a 2006 net stranded cost write-off of $112 million related to the September 2006 MPSC order regarding stranded costs and a $13 million decrease in our asset retirement obligation at our Fermi 1 nuclear facility, partially offset by $58 million of increased amortization of regulatory assets and $13 million of higher depreciation expense due to increased levels of depreciable plant assets.

Taxes other than income decreased $45 million in 2008 due to the Michigan Single Business Tax (SBT) expense in 2007, which was replaced with the Michigan Business Tax (MBT) in 2008. The MBT is accounted for in the Income Tax provision.

Asset (gains) losses and reserves, net decreased $9 million in 2008 and increased $14 million in 2007 due to a 2007 $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).

Other (income) and deductions expense increased $6 million in 2008 and decreased $17 million in 2007. The 2008 increase is attributable to $15 million of investment losses in a trust utilized for retirement benefits and $3 million of miscellaneous expenses offset by higher capitalized interest of $12 million. The 2007 decrease is attributable to a $10 million contribution to the DTE Energy Foundation in 2006 that did not recur in 2007, $3 million of higher interest income and $17 million of increased miscellaneous utility related services, partially offset by $16 million of higher interest expense.

Outlook — We will move forward in our efforts to continue to improve the operating performance and cash flow of Detroit Edison. We continue to resolve outstanding regulatory issues by pursuing regulatory and/or legislative solutions. Many of these issues and problems have been addressed by the legislation signed by the Governor of Michigan in October 2008, discussed more fully in the Overview section. Looking forward, additional issues, such as volatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans, health care costs and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will continue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.

Due to the economy and credit market conditions, in the near term, we are reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust the timing of projects as appropriate. Long term, we will be required to invest an estimated $2.8 billion on emission controls through 2018. We intend to seek recovery of these investments in future rate cases.

Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in over 20 years. Should our economic and regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant.

On September 18, 2008, Detroit Edison submitted a Combined Operating License Application with the NRC for construction and operation of a possible 1,500 MW nuclear power plant at the site of the company’s existing Fermi 2 nuclear plant. We have not decided on construction of a new base-load nuclear plant; however, by completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005. In addition, Detroit Edison is also moving ahead with plans for renewable energy resources and an aggressive energy efficiency program.

The following variables, either individually or in combination, could impact our future results:

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

	•		Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on cash equivalents and investments;

	•		Economic conditions within Michigan and corresponding impacts on demand for electricity;

	•		Collectibility of accounts receivable;

	•		Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions;

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

	•		Our ability to reduce costs and maximize plant and distribution system performance;

	•		Variations in market prices of power, coal and gas;

	•		Weather, including the severity and frequency of storms;

	•		The level of customer participation in the electric Customer Choice program; and

	•		Any potential new federal and state environmental, renewable energy and energy efficiency requirements.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Factors impacting income: Gas Utility’s net income attributable to DTE Energy Company increased $15 million in 2008 and $20 million in 2007. The 2008 and 2007 increases were due primarily to higher gross margins.


	2008			2007			2006
	(In millions)
Operating Revenues	$	2,152		$	1,875		$	1,849
Cost of Gas		1,378			1,164			1,157

Gross Margin		774			711			692
Operation and Maintenance		464			429			431
Depreciation and Amortization		102			93			94
Taxes Other Than Income		48			56			53
Asset (Gains) and Losses, Net		(26	)		(3	)		—

Operating Income		186			136			114
Other (Income) and Deductions		60			43			53
Income Tax Provision (Benefit)		41			23			11

Net Income Attributable to DTE Energy Company	$	85		$	70		$	50

Operating Income as a Percent of Operating Revenues		9	%		7	%		6	%

Gross margin increased $63 million and $19 million in 2008 and 2007, respectively. The increase in 2008 reflects $49 million from the uncollectible tracking mechanism, $15 million related to the impacts of colder weather, $10 million favorable result of lower lost gas recognized and higher valued gas received as compensation for transportation of third party customer gas, $7 million of 2007 GCR disallowances, and $6 million of appliance repair revenue. The 2008 improvement was partially offset by $19 million of lower storage services revenue and $12 million from customer conservation and lower volumes. The increase in 2007 is primarily due to $21 million from the favorable effects of weather in 2007 and $28 million related to an increase in midstream services including storage and transportation, partially offset by a $26 million unfavorable impact in lost gas recognized and $7 million in GCR disallowances. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.


	2008		2007		2006
Gas Markets (in Millions)
Gas sales	$	1,824	$	1,536	$	1,541
End user transportation		143		140		135

		1,967		1,676		1,676
Intermediate transportation		73		70		69
Storage and other		112		129		104

	$	2,152	$	1,875	$	1,849

Gas Markets (in Bcf)
Gas sales		148		148		138
End user transportation		123		132		136

		271		280		274
Intermediate transportation		438		399		373

		709		679		647

Operation and maintenance expense increased $35 million in 2008 and decreased $2 million in 2007. The 2008 increase is primarily attributable to $56 million of higher uncollectible expenses, partially offset by $14 million of lower corporate support expenses and $14 million of reduced pension and retiree health benefit costs. The increase in uncollectible expense is partially offset by increased revenues from the uncollectible tracking mechanism included in the gross margin discussion. The 2007 decrease was attributed to $4 million of lower uncollectible expense and $4 million of reduced corporate support expenses, partially offset by $5 million in increased information systems implementation costs.

Other Asset (gains) losses, net increased $23 million in 2008 and $3 million in 2007. Both increases are primarily attributable to the sale of base gas.

Outlook — Higher gas prices and deteriorating economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s GCR and uncollectible true-up mechanisms. We will continue to seek opportunities to improve productivity, minimize lost gas, remove waste and decrease our costs while improving customer satisfaction.

Unfavorable national and regional economic trends have resulted in negative customer growth in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.

The following variables, either individually or in combination, could impact our future results:

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

	•		Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on cash equivalents and investments;

	•		Economic conditions within Michigan and corresponding impacts on demand for gas and levels of lost or stolen gas;

	•		Collectibility of accounts receivable;

	•		Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions;

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

	•		Our ability to reduce costs and maximize distribution system performance;

	•		Variations in market prices of gas;

	•		Weather;

	•		Customer conservation;

	•		Volatility in the short-term storage markets which impact third-party storage revenues;

	•		Extent and timing of any base gas sales;

	•		Any potential new federal and state environmental, renewable energy and energy efficiency requirements.

NON-UTILITY OPERATIONS

Gas Midstream

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

Factors impacting income: Net income attributable to DTE Energy Company increased $4 million and $6 million in 2008 and 2007, respectively. The 2008 increase is due to higher storage revenues related to expansion of capacity and higher other income primarily driven by higher equity earnings from our investments in the Vector and Millennium Pipelines, partially offset by a higher tax provision due to the MBT in 2008. Net income attributable to DTE Energy Company was higher in 2007 due to higher storage revenues and lower expenses due to the Washington 10 restructuring during 2006.


	2008			2007			2006
	(In millions)
Operating Revenues	$	71		$	66		$	63
Operation and Maintenance		12			13			22
Depreciation and Amortization		5			6			3
Taxes Other Than Income		3			3			4
Asset (Gains) and Losses, Net		1			(1	)		(1	)

Operating Income		50			45			35
Other (Income) and Deductions		(12	)		(7	)		(8	)
Income Tax Provision		24			18			15

Net Income Attributable to DTE Energy	$	38		$	34		$	28

Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, an additional 7 Bcf of storage capacity was placed in service. Future additions to storage capacity of approximately 3 Bcf will occur over the next few months. Vector Pipeline placed into service its Phase 1 expansion for approximately 200 MMcf/d in November 2007. In addition, Vector Pipeline received FERC approval in June 2008 to build one additional compressor station, which will expand the Vector Pipeline by approximately 100 MMcf/d, with a proposed in-service date of November 2009. Adding another compressor station will bring the system from its current capacity of about 1.2 Bcf/d up to 1.3 Bcf/d in 2009. Both the 2007 and 2009 expansion projects are supported by customers under long-term contracts. Millennium Pipeline was placed in service in December 2008 and currently has nearly 85% of its capacity sold to customers under long-term contracts.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in northern Texas. In June 2007, we sold our Antrim shale gas exploration and production business in northern Michigan for gross proceeds of $1.262 billion.

In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 75 Bcf of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale. We recognized a gain of $128 million ($81 million after-tax) on the sale in 2008.

Factors impacting income: The 2008 results include the gain recognized on the sale of our Barnett shale property described above. In addition, lower gas sales volumes were offset by higher commodity prices and higher gas and oil production from retained wells in 2008 compared to 2007. The 2007 results reflect the recording of $323 million of losses on financial contracts related to expected Antrim gas production and sales through 2013.


	2008			2007			2006
	(In millions)
Operating Revenues	$	48		$	(228	)	$	99
Operation and Maintenance		22			36			37
Depreciation, Depletion and Amortization		12			22			27
Taxes Other Than Income		1			8			11
Asset (Gains) and Losses, Net		(120	)		27			(3	)

Operating Income (Loss)		133			(321	)		27
Other (Income) and Deductions		2			13			13
Income Tax Provision (Benefit)		47			(117	)		5

Net Income (Loss) Attributable to DTE Energy	$	84		$	(217	)	$	9

Operating revenues increased $276 million in 2008 and decreased $327 million in 2007. The 2007 decrease reflects the recording of $323 million of losses during 2007 on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. In conjunction with the Antrim sale, Antrim reclassified amounts held in accumulated other comprehensive income, reducing operating revenues in the 2007 period by $323 million. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $47 million in 2008 as compared to 2007. The decreases were principally due to lower natural gas sales volumes as a result of our monetization initiatives, partially offset by higher commodity prices and higher gas and oil production on retained wells.

Other assets (gains) losses, net increased $147 million in 2008 due to the gain on sale of Barnett shale core properties offset by $8 million of impairment losses primarily related to leases on unproved acreage that expire in 2009 that we do not anticipate developing due to current economic conditions. The $30 million decrease in 2007 was primarily due to the recording of impairment losses of $27 million in 2007 related to the write-off of unproved properties and the expiration of leases in the southern expansion area of the Barnett shale.

Outlook — We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $96 million in the Barnett shale in 2008. During 2009, we expect to invest approximately $25 million to drill 15 to 25 new wells and achieve Barnett shale production of approximately 5 to 6 Bcfe of natural gas from our remaining properties, compared with approximately 5 Bcfe in 2008.

Power and Industrial Projects

During the third quarter of 2007, we announced plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second quarter of 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, our work on this planned monetization was discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used.

Factors impacting income: Net income attributable to DTE Energy Company decreased $9 million in 2008 and increased $107 million in 2007.


	2008			2007			2006
	(In millions)
Operating Revenues	$	987		$	1,244		$	1,053
Operation and Maintenance		899			1,143			972
Depreciation and Amortization		34			41			49
Taxes other than Income		12			13			13
Other Asset (Gains) and Losses, Reserves and Impairments, Net		6			—			76

Operating Income (Loss)		36			47			(57	)
Other (Income) and Deductions		(20	)		(11	)		43
Income Taxes Provision (Benefit)		18			18			(31	)
Production Tax Credits		(7	)		(11	)		(12	)

Net Income (Loss)		45			51			(57	)
Noncontrolling Interests		5			2			1

Net Income (Loss) Attributable to DTE Energy Company	$	40		$	49		$	(58	)

Operating revenues decreased $257 million in 2008. This was primarily attributable to $177 million of reductions in coal transportation and trading volumes and $28 million for the impact of a customer electing to purchase coal directly from the supplier. Revenues in 2007 increased $191 million reflecting a new long-term utility services contract with a large automotive company, higher coke prices and sales volumes in addition to higher volumes at several other projects. Additionally, revenue was earned for a one-time fee from the sale of an asset we operated for a third party. In 2007, revenues were impacted by higher synfuel related volumes and increases in trading volumes related to both coal and emissions.

Operation and maintenance expense decreased $244 million in 2008 and increased $171 million in 2007. The 2008 decrease mostly reflects $174 million of lower coal transportation costs driven by reduced sales combined with a reduction in coal trading results. The 2007 increase was due to higher synfuel related production and higher trading volumes related to coal and emissions.

Depreciation and amortization expense decreased $7 million in 2008 and $8 million in 2007 due primarily to the suspension of $6 million of depreciation expense in the fourth quarter of 2007 related to the assets held for sale, the sale of a generation facility during the year and reduced depreciation expense as a result of asset impairments at several biomass landfill sites in 2006.

Other assets (gains) losses, reserves and impairments, net expense decreased $6 million in 2008 and decreased $76 million in 2007. The 2008 decrease is primarily attributable to a loss of approximately $19 million related to the valuation adjustment for the cumulative depreciation and amortization upon reclassification of certain project assets as held and used. Partially offsetting the 2008 loss were gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production. The 2007 decrease is due to impairments recognized in 2006 at natural gas- fired generating plants, long-lived assets at several landfill gas recovery sites and fixed assets and patents at our waste coal recovery business.

Other (income) and deductions were higher by $9 million in 2008 due primarily to higher inter-company interest. The 2007 decrease was due primarily to a realized gain of $8 million on the sale of a 50 percent equity interest in a natural gas-fired generating plant and a $4 million gain recognized in 2007 on an installment sale of a coke battery facility.

Outlook — The deterioration in the U.S. economy is expected to continue to negatively impact our customers in the steel industry and we expect a corresponding reduction in demand for metallurgical coke and pulverized coal supplied to these customers in 2009. We supply onsite energy services to the domestic automotive manufacturers who have also been negatively affected by the economic downturn and constriction in the capital and credit markets. Our onsite energy services are delivered in accordance with the terms of long-term contracts which include termination payments in the event of plant closures or other events of default and have not been significantly impacted by the financial distress experienced by the automotive manufacturers. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on the results of our onsite energy projects. We continue to monitor developments in this sector. In 2009, we expect our coal transportation and marketing business to positively contribute to the results of this segment as our coal transportation, storage and blending services continue to grow. In 2011, our existing long-term rail transportation contract which gives us a competitive advantage will expire. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers.

Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional on-site energy projects to serve energy intensive industrial customers that are experiencing capital constraints due to the economic downturn. We will also continue to look for opportunities to acquire on-site energy projects and biomass fired generating projects for advantageous prices.

Energy Trading

Our Energy Trading segment focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions.

Factors impacting income: Net income attributable to DTE Energy Company increased $10 million in 2008 and decreased $64 million in 2007.


	2008		2007		2006
	(In millions)
Operating Revenues	$	1,388	$	924	$	828
Fuel, Purchased Power and Gas		1,235		806		607

Gross Margin		153		118		221
Operation and Maintenance		68		58		65
Depreciation and Amortization		5		5		6
Taxes Other Than Income		2		1		1

Operating Income (Loss)		78		54		149
Other (Income) and Deductions		5		5		4
Income Tax Provision (Benefit)		31		17		49

Net Income (Loss) Attributable to DTE Energy Company	$	42	$	32	$	96

Gross margin increased $35 million in 2008 and decreased $103 million in 2007. The 2008 increase is due to higher unrealized margin of $66 million offset by a decrease in realized margin of $31 million. The increase in unrealized margins includes $18 million in improved gains in the gas trading strategy, $26 million gains on economic hedges of storage positions due to falling gas prices, and the absence of $30 million in mark-to-market losses in June 2007 reflecting revisions of valuation estimates for natural gas contracts, offset by $10 million in losses on economic hedges in our gas transportation strategy. The decrease in realized margin is due to unfavorability of $28 million primarily from our power marketing and transmission optimization strategies, $34 million of unfavorability in our gas storage and full requirements strategies due to falling prices in 2008, offset by $31 million of improvement in our gas trading strategy. The 2007 decrease is attributable to approximately $30 million of unrealized losses for gas contracts related to revisions of valuation estimates for the long-dated portion of our energy contracts and $32 million due to absence of unrealized gains on economic storage hedges and positions in our full requirements strategy. Timing differences from 2005 that largely reversed and favorably impacted 2006 margin resulted in $11 million of realized unfavorability in 2007. Additionally, margins were unfavorably impacted by $13 million of lower realized gains from reduced merchant storage capacity in 2007 and $12 million of unfavorability in realized power positions.

Operation and maintenance expense increased $10 million in 2008 and decreased $7 million in 2007. The 2008 increase is due to higher payroll and incentive costs and allocated corporate costs. The 2007 decrease was due primarily to lower incentive expenses.

Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipeline transportation and certain storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. A source of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar year, but runs annually from April of one year to March of the next year. Our strategy is to economically manage the price risk of storage with futures, forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.

See Capital Resources and Liquidity and Fair Value sections that follow for additional discussion of our trading activities.

CORPORATE & OTHER

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

Factors impacting income: Corporate & Other results decreased by $596 million in 2008 and increased by $563 million in 2007. This is mostly attributable to the 2007 gain on the sale of the Antrim shale gas exploration and production business for approximately $900 million ($580 million after-tax) and variations in inter-company interest.

DISCONTINUED OPERATIONS

Synthetic Fuel

The Company discontinued the operations of our synthetic fuel production facilities as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel business generated operating losses that were offset by production tax credits.

Factors impacting income: Synthetic Fuel net income attributable to DTE Energy Company decreased $185 million in 2008 and increased $157 million in 2007. The decrease in 2008 was due to the cessation of operations of our synfuel facilities at December 31, 2007 and the final determination of the 2007 IRS reference price and inflation factor in 2008. The increase in 2007 was due to synfuel production occurring throughout the year in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006 and higher income from oil price hedges, partially offset by a higher phase-out of production tax credits due to high oil prices.


	2008			2007			2006
	(In millions)
Operating Revenues	$	7		$	1,069		$	863
Operation and Maintenance		9			1,265			1,019
Depreciation and Amortization		(2	)		(6	)		24
Taxes other than Income		(1	)		5			12
Asset (Gains) and Losses, Reserves and Impairments, Net(1)		(31	)		(280	)		40

Operating Income (Loss)		32			85			(232	)
Other (Income) and Deductions		(2	)		(9	)		(20	)
Income Taxes
Provision (Benefit)		13			98			14
Production Tax Credits		(1	)		(21	)		(23	)

		12			77			(9	)

Net Income (Loss)		22			17			(203	)
Noncontrolling Interests		2			(188	)		(251	)

Net Income Attributable to DTE Energy Company(1)	$	20		$	205		$	48


(1)		Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.

Operating revenues decreased $1,062 million in 2008 and increased $206 million in 2007. The 2008 drop is due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 activity reflects the increased value of 2007 synfuel production as a result of final determination of the IRS Reference Price and inflation factor. Synfuel production was higher in 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.

Operation and maintenance expense decreased $1,256 million in 2008 and increased $246 million in 2007. The 2008 reduction is due to the cessation of operations of our synfuel facilities at December 31, 2007. Activity for 2008 reflects adjustments to 2007 contractually defined cost sharing mechanisms with suppliers, as determined by applying the actual phase-out percentage. The 2007 increase reflects synfuel production occurring throughout 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.

Depreciation and amortization expense was lower by $30 million in 2007 as a result of reductions in asset retirement obligations in 2007 and the impairment of fixed assets at all nine synfuel projects in 2006.

Asset (gains) and losses, reserves and impairments, net decreased $249 million in 2008 and increased $320 million in 2007. The 2008 decrease was due to the cessation of operations of our synfuel facilities at December 31, 2007 and reflects the impact of reserve adjustments for the final phase-out percentage and true-ups of final payments and distributions to partners.

The increase in gains in 2007 reflects the annual partner payment adjustment, recognition of certain fixed gains that were reserved during the comparable 2006 period, higher hedge gains and the impact of one-time impairment charges and fixed note reserves recorded in 2006. In 2007 and 2006, we deferred gains from the sale of the synfuel facilities, including a portion of gains related to fixed payments. Due to the increase in oil prices, we recorded accruals for contractual partners’ obligations of $130 million in 2007 and $79 million in 2006 reflecting the probable refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be paid by our partners. In 2007, we reversed $3 million of other synfuel-related reserves and impairments and in 2006 recorded $78 million of other synfuel-related reserves and impairments. To economically hedge our exposure to the risk of an increase in oil prices and the resulting reduction in synfuel sales proceeds, we entered into derivative and other contracts. The derivative contracts are marked-to-market with changes in their fair value recorded as an adjustment to synfuel gains. We recorded net 2007 synfuel hedge mark-to-market gains of $196 million compared with net 2006 synfuel hedge mark-to-market gains of $60 million.

The following table displays the various pre-tax components that comprise the determination of synfuel gains and losses in 2008, 2007 and 2006.


Components of Asset (Gains) Losses, Reserves and Impairments, Net	2008			2007			2006
	(In millions)
Gains recognized associated with fixed payments	$	—		$	(172	)	$	(43	)
Gains recognized associated with variable payments		(32	)		(39	)		(14	)
Reserves recorded for contractual partners’ obligations		—			130			79
Other reserves and impairments, including partners’ share(1)		(1	)		(3	)		78
Hedge (gains) losses:
Hedges for 2006 exposure		—			—			(66	)
Hedges for 2007 exposure					(196	)		6

	$	(33	)	$	(280	)	$	40


(1)		Includes $70 million in 2006, representing our partners’ share of the asset impairment, included in Noncontrolling Interests.

Noncontrolling Interests decreased by $190 million and $63 million in 2008 and 2007, respectively. The 2008 reduction is due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2007 decrease reflects the lower net operating losses in 2007 due to the asset impairment charge we incurred in 2006, partially offset by an increased discount on higher sales levels for 2007.

See Note 3 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff Position FAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See also the “Fair Value” section.

Effective January 1, 2007, we adopted FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $5 million reduction to the January 1, 2007 balance of retained earnings.

Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares.

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. During 2008, our cash requirements were met primarily through operations and from our non-utility monetization program.

Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2009 of up to $1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We incurred environmental expenditures of approximately $270 million in 2008 and we expect over $2.9 billion of future capital expenditures through 2018 to satisfy both existing and proposed new requirements. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

We expect non-utility capital spending will approximate $175 million to $300 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.

Long-term debt maturing or remarketing in 2009 totals approximately $350 million.


	2008			2007			2006
	(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)

Operating activities:
Net income	$	553		$	787		$	183
Depreciation, depletion and amortization		899			926			1,014
Deferred income taxes		348			144			28
Gain on sale of non-utility business		(128	)		(900	)		—
Gain on sale of synfuel and other assets, net and synfuel impairment		(35	)		(253	)		28
Working capital and other		(78	)		421			203

		1,559			1,125			1,456


Investing activities:
Plant and equipment expenditures — utility		(1,183	)		(1,035	)		(1,126	)
Plant and equipment expenditures — non-utility		(190	)		(264	)		(277	)
Acquisitions, net of cash acquired		—			—			(42	)
Proceeds from sale of non-utility business		253			1,262			—
Proceeds (refunds) from sale of synfuels and other assets		(278	)		417			313
Restricted cash and other investments		(125	)		(50	)		(62	)

		(1,523	)		330			(1,194	)


Financing activities:
Issuance of long-term debt and common stock		1,310			50			629
Redemption of long-term debt		(446	)		(393	)		(687	)
Repurchase of long-term debt		(238	)		—			—
Short-term borrowings, net		(340	)		(47	)		291
Repurchase of common stock		(16	)		(708	)		(61	)
Dividends on common stock and other		(354	)		(370	)		(375	)

		(84	)		(1,468	)		(203	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	(48	)	$	(13	)	$	59

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 $1.6 billion in 2008, increased $434 million from the comparable 2007 period. The operating cash flow comparison primarily reflects higher net income, after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred taxes, and gains on sales of assets), and cash payments received related to our synfuel program hedges.

Cash from operations totaling $1.1 billion in 2007 decreased $331 million from the comparable 2006 period. The operating cash flow comparison primarily reflects a decrease in net income after adjusting for non-cash items (depreciation, depletion and amortization and deferred taxes), and gains on sales of businesses. The decrease was mostly driven by taxes attributable to our non-utility monetization program.

Cash from Investing Activities

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

Net cash used for investing activities was approximately $1.5 billion in 2008, compared with cash from investing activities of $330 million in 2007. The change was primarily driven by our non-utility monetization program and final refund payments to our synfuel partners in 2008.

Net cash from investing activities increased $1.5 billion in 2007, due primarily to the sale of our Antrim shale gas exploration and production business and lower capital expenditures.

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% to 52%, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet.

Net cash used for financing activities was $84 million in 2008, compared to net cash used of approximately $1.5 billion for the same period in 2007. The change was primarily attributable to increased proceeds from the issuance of long-term debt, net of debt redemptions and repurchases, and lower repurchases of common stock.

Net cash used for financing activities increased $1.3 billion in 2007 primarily related to the repurchase of common stock, a decrease in short-term borrowings and a lower level of long-term debt issuances, partially offset by lower debt redemptions.

Outlook

We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.

Recent distress in the financial markets has had an adverse impact on financial market activities, including extreme volatility in security prices and severely diminished liquidity and credit availability. Pursuant to the failures of large financial institutions, the credit situation rapidly evolved into a global crisis resulting in a number of international bank failures and declines in various stock indexes, and large reductions in the market value of equities and commodities worldwide. The crisis has led to increased volatility in the markets for both financial and physical assets, as the failures of large financial institutions resulted in sharply reduced trading volumes and activity. The effects of the credit situation will continue to be monitored.

We have experienced difficulties in accessing the commercial paper markets for short-term financing needs and an extended period of distress in the capital markets could have a negative impact on our liquidity in the future. Short-term borrowings, principally in the form of commercial paper, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities. Beginning late in the third quarter of 2008, access to the commercial paper markets was sharply reduced and, as a result, we drew against our unsecured credit lines to supplement other sources of funds to meet our short-term liquidity needs. We continue to access the long-term bond markets as evidenced by certain financings completed in the fourth quarter of 2008. Since December 31, 2008, we have benefited from substantially improved liquidity and pricing in the commercial paper market. As a result, we anticipate repayment of our credit facility draws during the first quarter of 2009.

Approximately $1.2 billion of our total short-term credit arrangements of $2.1 billion expire between June and December 2009, with the remainder expiring in October 2010. In anticipation of a significantly more challenging credit market, we expect to pursue the renewal of $975 million of our syndicated revolving credit facilities before their expiration in October. Given current conditions in the credit markets, we anticipate that the new facilities will vary significantly from our current facilities with respect to such items as bank participation, allocation levels, pricing and covenants. We are currently in discussions with our existing bank group and actively pursuing potential new candidates for inclusion, as we anticipate that a number of banks in our current bank group will elect not to participate in the renewal or will alter their commitment level. Initial indications are that pricing is likely to be significantly higher due to market-wide re-pricing of risk. Multi-year agreements are still possible, however, the recent trend in the marketplace is toward 364 day facilities. Several bi-lateral credit facilities totaling approximately $200 million will also expire in 2009 and we are evaluating the need for replacement.

Our benefit plans have not experienced any direct significant impact on liquidity or counterparty risk due to the turmoil in the financial markets. As a result of losses experienced in the financial markets, our benefit plan assets experienced negative returns for 2008, which will result in increased benefit costs and higher contributions in 2009 and future years than in the recent past or than originally planned.

We have assessed the implications of these factors on our current business and determined that there has not been a significant impact to our financial position and results of operations in 2008. While the impact of continued market volatility and turmoil in the credit markets cannot be predicted, 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 and 13 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) 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, 2008:


									2014
Contractual Obligations	Total		2009		2010-2011		2012-2013		and Beyond
	(In millions)
Long-term debt:
Mortgage bonds, notes and other	$	6,687	$	220	$	1,294	$	671	$	4,502
Securitization bonds		1,064		132		290		341		301
Trust preferred-linked securities		289		—		—		—		289
Capital lease obligations		91		15		26		18		32
Interest		6,104		484		884		722		4,014
Operating leases		238		36		57		46		99
Electric, gas, fuel, transportation and storage purchase obligations(1)		5,665		2,972		1,813		160		720
Other long-term obligations(2)(3)(4)		201		41		94		25		41

Total obligations	$	20,339	$	3,900	$	4,458	$	1,983	$	9,998


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

(2)		Includes liabilities for unrecognized tax benefits of $72 million.

(3)		Excludes other long-term liabilities of $182 million not directly derived from contracts or other agreements.

(4)		At December 31, 2008, 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 Critical Accounting Estimates section of MD&A and in Note 18 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K).

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. 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 credit 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 credit 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 the parent 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. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews. The following table shows our credit rating as determined by three nationally recognized credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.


		Credit Rating Agency
		Standard &	Moody’s	Fitch
Entity	Description	Poor’s	Investors Service	Ratings
DTE Energy	Senior Unsecured Debt	BBB-	Baa2	BBB
	Commercial Paper	A-2	P-2	F2
Detroit Edison	Senior Secured Debt	A-	A3	A-
	Commercial Paper	A-2	P-2	F2
MichCon	Senior Secured Debt	BBB+	A3	BBB+
	Commercial Paper	A-2	P-2	F2

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 Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

Regulation

A significant portion of our business is subject to regulation. Detroit Edison and MichCon currently meet the criteria of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of 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 discontinuing the application of SFAS No. 71 for some or all of our businesses. Management believes that currently available facts support the continued application of SFAS No. 71 and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment. See Note 5 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

Derivatives and Hedging Activities

Risk management and trading activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives are recorded at fair value and shown as Derivative Assets or Liabilities in the Consolidated Statements of Financial Position. Derivatives are measured at fair value, and 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. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchases and normal sales criteria specified in the standard. 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. Essentially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.

Fair value is 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. The fair value of derivative contracts is determined from a combination of active quotes, published indexes and mathematical valuation models. We generally derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods in which external market data is not readily observable, we estimate value using mathematical valuation models. Valuation models require various inputs and assumptions, including forward prices, volatility, interest rates, and exercise periods. For those inputs which are not observable, we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes,

current market transactions or other observable market information may require us to record gains or losses at inception of new derivative contracts.

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 the Fair Value section. See Notes 15 and 16 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

Allowance for Doubtful Accounts

We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends, economic conditions, age of receivables and other information. Higher customer bills due to increased electricity and gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2008 and 2007. 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 accounts tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. Detroit Edison has requested a similar tracking mechanism in its rate request filed January 26, 2009. However, failure to make continued progress in collecting our past due receivables in light of volatile energy prices and deteriorating economic conditions would unfavorably affect operating results and cash flow.

Asset Impairments

Goodwill

Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing these impairment tests, 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. 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.

As of December 31, 2008, our goodwill totaled $2 billion with 97 percent of this amount allocated to our utility reporting units. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment.

We performed our annual impairment test on October 1, 2008 and determined that the estimated fair value of our reporting units exceeded their carrying value and no impairment existed. During the fourth quarter of 2008, the closing price of DTE Energy’s stock declined by approximately 11% and at December 31, 2008 was approximately 3 percent below its book value per share. The market price of an individual equity security (and therefore the market capitalization of an entity with publicly traded equity securities) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over an entity. An acquirer is often willing to pay more for equity securities that give it a controlling interest (i.e. a control premium) than an investor would pay for a number of equity securities representing less than a controlling interest. That control premium may cause the fair value of the entity to exceed its market capitalization. In assessing whether the recent modest decline in the trading price of DTE Energy’s common stock below its book value was an indication of impairment, we considered the following factors: (1) the relatively short duration and modest decline in the trading price of DTE Energy’s common stock; (2) the impact of the national and regional recession on DTE Energy’s future operating results and anticipated cash flows; (3) the favorable results of the recently performed annual impairment test and (4) a comparison of book value to the traded market price, including the impact of a control premium. The implied control premium of approximately 3 percent needed to equate DTE Energy’s market price to its book value was below the low end of the range of control premiums observed in recent transactions. As a result of this assessment, we determined that the decline in market price did not represent a trigger event at December 31, 2008 and an updated impairment test was not performed.

We will continue to monitor our estimates and assumptions regarding future cash flows. While we believe our assumptions are reasonable, actual results may differ from our projections.

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 4 of Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

Our Power and Industrial Projects segment has long-term contracts with General Motors Corporation (GM) and Ford Motor Company (Ford) to provide onsite energy services at certain of their facilities. At December 31, 2008, the book value of long-lived assets used in the servicing of these facilities was approximately $85 million. In addition, we have an equity investment of approximately $40 million in an entity which provides similar services to Chrysler LLC (Chrysler). These companies are in financial distress, with GM and Chrysler recently receiving loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. We consider the recent announcements by these companies as an indication of possible impairment due to a significant adverse change in the business climate that could affect the value of our long-lived assets as described in SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” and have performed an impairment test on these assets. Based on our current undiscounted cash flow projections we have determined that we do not have an impairment as of December 31, 2008. We have also determined that we do not have an other than temporary decline in our Chrysler-related equity investment as described in APB 18, “The Equity Method of Accounting for Investments in Common Stock.” As the circumstances surrounding the long-term viability of these entities are dynamic and uncertain, we continue to monitor developments as they occur and will update our impairment analyses accordingly.

Pension and Postretirement Costs

We sponsor defined benefit pension plans and postretirement benefit plans for substantially all of the 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 for pension plans of $24 million in 2008, $76 million in 2007, and $134 million in 2006. Postretirement benefits costs for all plans were $142 million in 2008, $188 million in 2007 and $197 million in 2006. Pension and postretirement benefits costs for 2008 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.75%. In developing our expected long-term rate of return assumption, 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 2009 expected long-term rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 55% in equity markets, 20% in fixed income markets, and 25% 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 believe that 8.75% is a reasonable long-term rate of return on our plan assets for 2009. 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. SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” allow the MRV of plan assets to 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 recorded. Volatile financial markets contributed to our investment performance resulting in unrecognized net losses. As of December 31, 2008, we had $1.1 billion 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 plan pension and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis increased from 6.5% at December 31, 2007 to 6.9% at December 31, 2008. Due to the combination of recent company contributions, losses on plan assets due to negative financial market performance and higher discount rates, we estimate that our 2009 total pension costs will approximate $57 million compared to $24 million in 2008 and our 2009 postretirement benefit costs will approximate $208 million compared to $142 million in 2008. 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 pension cost tracking mechanism, implemented in November 2004, that provided for recovery or refunding of pension costs above or below amounts reflected in Detroit Edison’s base rates, at the request of Detroit Edison was not reauthorized by the MPSC in its rate order effective January 1, 2009. In April 2005, the MPSC approved the deferral of the non-capitalized portion of MichCon’s negative pension expense. MichCon will record 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 2008 pension costs by approximately $39 million. Lowering the discount rate and the salary increase assumptions by one-percentage-point would have increased our 2008 pension costs by approximately $37 million. Lowering the health care cost trend assumptions by one-percentage-point would have decreased our postretirement benefit service and interest costs for 2008 by approximately $26 million.

At December 31, 2006, we adopted SFAS No. 158 and recognized the underfunded status of our pension and other postretirement plans. The impact of the adoption of SFAS No. 158 was an increase in pension and postretirement benefit liabilities of approximately $1.3 billion in 2006. We requested and received agreement from the MPSC to record the additional liability amounts for the Detroit Edison and MichCon benefit plans on the Statement of Financial Position as a regulatory asset. As a result, regulatory assets were increased by approximately $1.2 billion. The remainder of the increase in pension and postretirement benefit liabilities is included in accumulated other comprehensive loss, net of tax. In 2008, as required by SFAS 158, we changed the measurement date of our pension and postretirement benefit plans from November 30 to December 31. As a result we recognized adjustments of $17 million ($9 million after-tax) and $4 million to retained earnings and regulatory liabilities, respectively, which represents approximately one month of pension and other postretirement benefit cost for the period from December 1, 2007 to December 31, 2008.

The market value of our pension and postretirement benefit plan assets has been affected in a negative manner by the financial markets. The value of our plan assets was $3.8 billion at November 30, 2007 and $2.8 billion at December 31, 2008. At December 31, 2008 our pension plans were underfunded by $877 million and our other postretirement benefit plans were underfunded by $1.4 billion, reflected in noncurrent assets, current liabilities, and noncurrent liabilities, respectively. The decline relative to 2007 funding levels results from negative investment performance returns in 2008.

Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made contributions to our pension plans of $100 million and $150 million in 2008 and 2007, respectively. Also, we contributed $50 million to our pension plans in January 2009. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making up to a $250 million contribution to our pension plans in 2009 and up to $1.1 billion over the next five years. We made postretirement benefit plan contributions of $116 million and $76 million in 2008 and 2007, respectively. In January 2009, we contributed $40 million to our postretirement benefit plans. We are required by orders issued by the MPSC to make postretirement benefit contributions at least equal to the amounts included in Detroit Edison’s and MichCon’s base rates. As a result, we expect to make up to a $130 million contribution to our postretirement plans in 2009 and, subject to MPSC funding requirements, up to $750 million over the next five years.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $14 million in 2008, $16 million in 2007, and $17 million in 2006.

See Note 18 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) 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, 2008, 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 in accordance with FIN 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. 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 that are outside the scope of FIN 48 and accounted for under SFAS No. 5 and FASB Statement of Financial Accounting Concepts No. 6.

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 carryforwards, 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. While we believe the resulting tax reserve balances as of December 31, 2008 and December 31, 2007 are appropriately accounted for in accordance with FIN 48, SFAS No. 5, SFAS No. 109 and FASB Statement of Financial Accounting Concepts No. 6, as applicable, 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 8 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

ENVIRONMENTAL MATTERS

Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which DTE or its subsidiaries, including Detroit Edison and MichCon are responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the time of the remediation work, changes in technology, regulations and the requirements of local governmental authorities. These matters, if resolved in a manner different from the estimates, could have a material effect on our results of operation and financial position, to the extent the costs are not recovered through the base rates set for our utilities. See Note 17 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

FAIR VALUE

SFAS No. 157 — Fair Value Measurements

Effective January 1, 2008, we adopted SFAS No. 157. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff Position FAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See Note 15 of the Notes to Consolidated Financial Statements in Exhibit 99.3 (Item 8 from 2008 Form 10-K) of this Report.

Derivative Accounting

The accounting standards for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as Derivative assets or liabilities, at the fair value of the contract. The recorded fair value of the contract is then adjusted at each reporting date, in the Consolidated Statements of Operations, to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting. Changes in the fair value of a designated derivative that is highly effective as a cash flow hedge are recorded as a component of Accumulated other comprehensive income, net of taxes, until the hedged item affects income. These amounts are subsequently reclassified into earnings as a component of the value of the forecasted transaction, in the same period as the forecasted transaction affects earnings. The ineffective portion of the fair value changes is recognized in the Consolidated Statements of Operations immediately.

Fair value is 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. The fair value of derivative contracts are determined from a combination of quoted market prices, published indexes and mathematical valuation models. Where possible, we derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods or locations in which external market data is not readily observable, we estimate value using mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates and exercise periods. For those inputs which are not observable, we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes, current market transactions or other observable market information may require us to record gains or losses at inception of new derivative contracts. Our credit risk and the credit risk of our counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the year ended December 31, 2008.

Contracts we typically classify as derivative instruments include power, gas, certain coal and oil forwards, futures, options and swaps, and foreign currency contracts. Items we do not generally account for as derivatives include proprietary gas inventory, certain gas storage and transportation arrangements, and gas and oil reserves.

We manage our MTM risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our 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 subsequent tables contain the following four categories represented by their operating characteristics and key risks:

•

Economic Hedges — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned 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.

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

	•		Proprietary 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 — Primarily represents derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein.

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

The following tables provide details on changes in our MTM net asset (or liability) position during 2008:


	Economic			Structured			Proprietary
	Hedges			Contracts			Trading			Other			Total
	(In millions)
MTM at December 31, 2007	$	4		$	(365	)	$	8		$	2		$	(351	)

Reclassify to realized upon settlement		(17	)		47			11			(2	)		39
Changes in fair value recorded to income		34			89			20			1			144
Changes in fair value recorded in regulatory liabilities		—			—			—			2			2
Amortization of option premiums		—			(1	)		(1	)		—			(2	)

Amounts recorded to income		17			135			30			1			183
Cumulative effect adjustment to initially apply SFAS No. 157, pre-tax		—			7			—			—			7
Amounts recorded in other comprehensive income		—			—			—			6			6
Change in collateral held by (for) others		(3	)		(7	)		(6	)		—			(16	)
Option premiums paid and other		—			8			(10	)		—			(2	)

MTM at December 31, 2008	$	18		$	(222	)	$	22		$	9		$	(173	)

A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business was mitigated by financial contracts that hedged our price risk exposure through 2013. The contracts were retained when the Antrim business was sold and offsetting financial contracts were put into place to effectively settle these positions. The contracts will require payments through 2013. These contracts represent a significant portion of the above net mark-to-market liability.

The following table provides a current and noncurrent analysis of Derivative assets and liabilities, as reflected on the Consolidated Statements of Financial Position as of December 31, 2008. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.


	Economic			Structured			Proprietary								Assets
	Hedges			Contracts			Trading			Eliminations			Other		(Liabilities)
	(In millions)
Current assets	$	36		$	165		$	116		$	(9	)	$	8	$	316
Noncurrent assets		8			129			3			(1	)		1		140

Total MTM assets		44			294			119			(10	)		9		456

Current liabilities		(15	)		(209	)		(70	)		9			—		(285	)
Noncurrent liabilities		(11	)		(307	)		(27	)		1			—		(344	)

Total MTM liabilities		(26	)		(516	)		(97	)		10			—		(629	)

Total MTM net assets (liabilities)	$	18		$	(222	)	$	22		$	—		$	9	$	(173	)


										2012
										and			Total Fair
Source of Fair Value	2009			2010			2011			Beyond			Value
	(In millions)
Economic Hedges	$	21		$	(7	)	$	(2	)	$	6		$	18
Structured Contracts		(45	)		(64	)		(44	)		(69	)		(222	)
Proprietary Trading		46			(24	)		—			—			22
Other		9			—			—			—			9

Total	$	31		$	(95	)	$	(46	)	$	(63	)	$	(173	)