Edgar Filing: DTE ENERGY CO

FORM 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended September 30, 2008

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


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

2000 2nd Avenue, Detroit, Michigan		48226-1279
(Address of principal executive offices)		(Zip Code)

313-235-4000
(Registrant’s telephone number, including area code)

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

Yes þ No o

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

At September 30, 2008, 163,025,446 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.

DTE Energy Company
Quarterly Report on Form 10-Q
Quarter Ended September 30, 2008

TABLE OF CONTENTS


	Page
Definitions		1

Forward-Looking Statements		3

Part I — Financial Information

Item 1. Financial Statements

Consolidated Statements of Operations (Unaudited)		33

Consolidated Statements of Financial Position (Unaudited)		34

Consolidated Statements of Cash Flows (Unaudited)		36

Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Unaudited)		37

Notes to Consolidated Financial Statements (Unaudited)		38

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		5

Item 3. Quantitative and Qualitative Disclosures About Market Risk		29

Item 4. Controls and Procedures		32

Part II — Other Information

Item 1. Legal Proceedings		63

Item 1A. Risk Factors		63

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		64

Item 6. Exhibits		65

Signature		65
EX-4-250
EX-4-251
EX-31-43
EX-31-44
EX-32-43
EX-32-44

Definitions


Company		DTE Energy Company and any subsidiary companies

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

Customer Choice		Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas

Detroit Edison		The Detroit Edison Company, a direct wholly-owned subsidiary of DTE Energy, and any subsidiary companies

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

EPA		United States Environmental Protection Agency

FERC		Federal Energy Regulatory Commission

GCR		A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers

MDEQ		Michigan Department of Environmental Quality

MichCon		Michigan Consolidated Gas Company, an indirect wholly-owned subsidiary of DTE Energy, and any subsidiary companies

MISO		Midwest Independent System Operator, a Regional Transmission Organization

MPSC		Michigan Public Service Commission

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

NRC		Nuclear Regulatory Commission

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

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

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

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

SFAS		Statement of Financial Accounting Standards

Stranded costs		Costs incurred by utilities in order to serve customers in a regulated environment that, absent special regulatory approval, would not otherwise be recoverable if customers switch to alternative energy suppliers

Subsidiaries		The direct and indirect subsidiaries of DTE Energy Company

Synfuels		The fuel produced through a process involving chemically modifying and binding particles of coal, used for power generation and coke production; synfuel production through December 31, 2007 generated production tax credits


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

Units of Measurement

Bcf		Billion cubic feet of gas

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

GWh		Gigawatthour of electricity

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MMcf		Million cubic feet of gas

MW		Megawatt of electricity

MWh		Megawatthour of electricity

Forward-Looking Statements

Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

	•		the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;

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

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

	•		environmental issues, laws, regulations, and the cost of remediation and compliance, including actual and potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;

	•		nuclear regulations and operations associated with nuclear facilities;

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

	•		employee relations and the impact of collective bargaining agreements;

	•		unplanned outages;

	•		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;

	•		the timing and extent of changes in interest rates;

	•		the level of borrowings;

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

	•		effects of competition;

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

	•		contributions to earnings by non-utility subsidiaries;

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

	•		the ability to recover costs through rate increases;

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

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

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

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

	•		amounts of uncollectible accounts receivable;

	•		binding arbitration, litigation and related appeals; and

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

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

Part I — Item 2.

DTE ENERGY COMPANY
Management’s Discussion and Analysis
of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with 2007 annual revenues in excess of $8 billion and assets of approximately $24 billion. 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.

Net income in the third quarter of 2008 was $177 million, or $1.08 per diluted share, compared to net income of $197 million, or $1.19 per diluted share, in the third quarter of 2007. Net income for the nine months ended September 30, 2008 was $417 million, or $2.56 per diluted share, compared to net income of $716 million, or $4.15 per diluted share, in the comparable period of 2007. The decrease for the quarter was due primarily to lower earnings in the Energy Trading business and synfuel related income included in discontinued operations, partially offset by improved results at the utilities and Power and Industrial Projects business. The decrease for the nine-month period was due primarily to $364 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $897 million ($574 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. The comparison for the nine-month period is also impacted by a 2008 gain of $128 million ($82 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:

•		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;

•		Impact of increased market demand on coal supply;

•		Challenges associated with nuclear fuel;

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

•		Monetization of portions of our Unconventional Gas Production business;

•		Results in our Energy Trading business;

•		Discontinuance of the Synthetic Fuel business;

•		Cost reduction efforts and required environmental and reliability-related capital investments; and

•		Ability to access capital markets for short and long-term financing, when needed.

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

UTILITY OPERATIONS

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

Our Gas Utility segment consists of MichCon and Citizens Gas Fuel Company (Citizens). MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 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.

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 nine months ended September 30, 2008, we experienced colder weather than in the nine months ended September 30, 2007.

Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure, resulting in power outages. Restoration and other expenses associated with storm-related power outages were $9 million and $52 million in the three and nine months ended September 30, 2008 as compared to $22 million and $52 million in the three and nine months ended September 30, 2007.

Collectibility of Accounts Receivable on Utility Operations — Both utilities continue to experience high levels of past due receivables, 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. The allowance for doubtful accounts expense for the two utilities is approximately $32 million for the quarter ended September 30, 2008 compared to $33 million for the quarter ended September 30, 2007. The allowance for doubtful accounts expense for the two utilities is approximately $168 million for the nine months ended September 30, 2008 compared to $101 million for the nine months ended September 30, 2007.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. MichCon’s operating revenues include a component representing ninety percent of the difference between the actual uncollectible expense for each year and $37 million, including carrying charges. An annual reconciliation proceeding before the MPSC is held. 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. We filed the 2007 reconciliation in March 2008, requesting an additional surcharge of approximately $34 million including a $1 million uncollected balance from the 2005 surcharge. We accrue interest income on the outstanding balances.

Impact of Regulatory Decisions on Utility Operations — Detroit Edison filed a general rate case in April 2007 requesting a $123 million, or 2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008, and in August 2007 filed a supplement to this filing to account for events which occurred subsequent to the initial filing. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. Also, the Michigan legislature enacted the Michigan Business Tax (MBT) in July 2007. The supplemental filing addressed the recovery of the merger control premium costs and the enactment of the MBT. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million. In February 2008, Detroit Edison filed an update to its April 2007 rate case filing, which includes the use of 2009 as the projected test year; a revised 2009 load forecast; 2009 estimates on environmental and advanced metering infrastructure capital expenditures; and adjustments to the MBT calculation. An MPSC order related to this filing is expected by early 2009. See Note 6 of the Notes to Consolidated Financial Statements.

The MPSC issued an order in August 2006 approving a settlement agreement providing for an annualized 2006 rate reduction of $53 million for Detroit Edison, effective September 2006. Beginning January 1, 2007 and continuing until April 13, 2008, one year from the April 13, 2007 general rate case filing, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $25 million during the period the rate reduction was in effect for 2008 and approximately $19 million and $53 million in the three and nine months ended September 30, 2007, respectively, as a result of this order. The revenue reduction is net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provides 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 $54 million. This settlement provides for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell through the end of 2008. During 2007, MichCon sold 0.75 Bcf of base gas and recognized a pre-tax gain of $5 million. MichCon did not sell base gas in the first nine months of 2008. 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 September 30, 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. 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 rate 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 expense during construction.

	•		M&A 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 a renewable energy and energy optimization (energy efficiency, energy conservation or load management) program in Michigan and provides for a separate funding surcharge to pay the cost of those programs.

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 would 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.

	•		Within 60 days after the passage of the new law, the MPSC is to issue a temporary order implementing this act.

	•		Within 90 days following the issuance of a temporary order, the utilities will file a Renewable Portfolio Standard (RPS) plan with the MPSC.

	•		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 long-term power purchase agreements.

	•		The bill also provides for a net metering program to be established by Commission 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 and installation costs.

	•		Incentives are potentially available for exceeding annual program targets. The financial incentive could be the lesser of 25% of the net cost reductions 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. 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, restructuring or recapitalization of certain non-utility businesses.

Beginning in the second quarter of 2008, we 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 10 of the Notes to Consolidated Financial Statements for further information on this realignment.

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 stable, long-term, fixed-price revenue contracts. The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance and technical support for Washington 28 and Washington 10 storage facilities. In addition, pursuant to a separate agreement, MichCon provides physical operations, maintenance and technical support for a portion of the Vector Pipeline system which MichCon leases to Vector. Gas Midstream is continuing its steady growth plan with the completion of two new storage capacity expansions and the expanding and building of new pipeline capacity to serve markets in the Midwest and Northeast United States.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 66,216 (64,183 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 Bcf 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 ($82 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 $80 million in the Barnett shale for the first nine months of 2008 and expect to invest an additional $15 million during the remainder of the year. During 2008, we expect to drill 35 new wells and achieve Barnett shale production of approximately 5 Bcfe of natural gas from our remaining properties, compared with approximately 7.7 Bcfe in 2007 from all properties, including those that were sold.

Power and Industrial Projects

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation services and marketing and develop biomass energy projects. This business 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 include pulverized coal and petroleum 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 and a biomass-fired electric generating plant. A second biomass-fired electric generating plant is currently under development pending certain regulatory and management approvals. This business 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 these coke batteries generates production tax credits. The business provides coal transportation 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 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 a Portion 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 were 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, optimization of contracted natural gas pipelines 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 in our results of operations. 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.

Results in our Energy Trading Business — 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 pipelines 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

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 effective 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 plants generated operating losses that were substantially offset by production tax credits. The value of a production tax credit is adjusted annually by an inflation factor published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds. The actual tax credit phase-out for 2007 was approximately 67%.

PERFORMANCE EXCELLENCE PROCESS

We continuously review and adjust our cost structure and seek improvements in our processes. In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process. This initiative was an extension of the DTE Energy Operating System initiative adopted in 2002. These initiatives represent the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements.

The primary goal is to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their rates. Additionally, we will need significant resources in the future to invest in the infrastructure required to provide safe, reliable and affordable energy. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function. The process is rigorous and challenging and seeks to yield sustainable performance improvements for our customers and shareholders. We have identified continuous improvement opportunities, including the Performance Excellence Process. To fully realize the benefits from this program, it was necessary to make significant up-front investments in our infrastructure and business processes, and we began to realize sustained net cost savings in 2007.

In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental costs to achieve (CTA), subject to the MPSC establishing a recovery mechanism. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million and $54 million of CTA in 2006 and 2007, respectively, as a regulatory asset and began amortizing deferred costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. Amortization of prior year deferred CTA costs was $4 million and $3 million for the three months ended September 30, 2008 and 2007, respectively, and $12 million and $8 million for the nine months ended September 30, 2008 and 2007, respectively. Detroit Edison deferred approximately $9 million and $18 million of CTA for the three months ended September 30, 2008 and 2007, respectively, and approximately $20 million and $39 million of CTA for the nine months ended September 30, 2008 and 2007, respectively. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon expects to seek a recovery mechanism in its next rate case in 2009.

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. From 2008 through 2012, our electric utility segment currently expects to invest approximately $5.8 billion (excluding investments in new base load generation capacity, if any), including increased environmental requirements, reliability enhancement projects and development of renewable energy resources. Our gas utility segment currently expects to invest approximately $850 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.

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;

	•		Improving our 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 10 of the Notes to Consolidated Financial Statements for further information on this realignment.The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

Net income by segment for the three and nine month periods ended September 30, 2008 and 2007 is as follows:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Net Income:
Electric Utility	$	159		$	107		$	251		$	207
Gas Utility		(15	)		(29	)		33			31
Non-Utility Operations:
Gas Midstream		11			9			27			25
Unconventional Gas Production		3			1			89			(208	)
Power and Industrial Projects		26			9			30			26
Energy Trading		19			45			36			33

Corporate & Other		(34	)		10			(69	)		482

Income (Loss) from Continuing Operations:
Utility		144			78			284			238
Non-utility		59			64			182			(124	)
Corporate & Other		(34	)		10			(69	)		482

		169			152			397			596
Discontinued Operations		8			45			20			120

Net Income	$	177		$	197		$	417		$	716

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Factors impacting income: Net income increased by $52 million in the third quarter of 2008 and $44 million for the nine-month period ended September 30, 2008. These increases were primarily due to lower expenses for operation and maintenance, depreciation and amortization, and taxes other than income, partially offset by lower gross margins.


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2008		2007		2008		2007
Operating Revenues	$	1,440	$	1,403	$	3,766	$	3,707
Fuel and Purchased Power		586		518		1,403		1,274

Gross Margin		854		885		2,363		2,433
Operation and Maintenance		292		386		1,019		1,114


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Depreciation and Amortization		193			203			563			583
Taxes Other Than Income		54			63			176			204
Other Asset (Gains) and Losses, Reserves, Net		(1	)		6			(1	)		12

Operating Income		316			227			606			520
Other (Income) and Deductions		67			70			212			213
Income Tax Provision		90			50			143			100

Net Income	$	159		$	107		$	251		$	207


Operating Income as a Percentage of Operating Revenues		22	%		16	%		16	%		14	%

Gross margin decreased $31 million in the third quarter of 2008 and $70 million in the nine-month period ended September 30, 2008. The 2008 decreases were due to the absence of the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and the unfavorable impacts of weather and service territory performance. 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. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. See Note 6 of the Notes to Consolidated Financial Statements.

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

Increase (Decrease) in Gross Margin Components Compared to Prior Year


(in Millions)	Three Months			Nine Months
Weather related impacts	$	(13	)	$	(32	)
Return of customers from electric Customer Choice		6			20
Service territory performance		(17	)		(24	)
Refundable pension cost		(6	)		(20	)
2005 PSCR reconciliation order in 2007		—			(34	)
April 2008 expiration of show-cause rate decrease		18			30
Other, net		(19	)		(10	)

Decrease in gross margin	$	(31	)	$	(70	)

Power Generated and Purchased


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Thousands of MWh)	2008			2007			2008			2007
Power Plant Generation
Fossil		10,566			11,055			31,153			31,729
Nuclear		2,405			2,352			7,156			7,195

		12,971			13,407			38,309			38,924
Purchased Power		2,486			2,765			5,725			5,885

System Output		15,457			16,172			44,034			44,809
Less Line Loss and Internal Use		(1,056	)		(1,160	)		(2,623	)		(2,568	)

Net System Output		14,401			15,012			41,411			42,241


Average Unit Cost ($/MWh)
Generation (1)	$	19.32		$	16.93		$	17.98		$	15.72

Purchased Power	$	88.43		$	69.61		$	73.23		$	68.03

Overall Average Unit Cost	$	30.43		$	25.94		$	25.16		$	22.59


(1)		Represents fuel costs associated with power plants.


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Thousands of MWh)	2008		2007		2008		2007
Electric Sales
Residential		4,595		4,836		11,955		12,340
Commercial		5,072		5,166		14,347		14,345
Industrial		3,327		3,278		10,074		9,974
Wholesale		700		718		2,123		2,170
Other		89		93		285		292

		13,783		14,091		38,784		39,121
Interconnections sales (1)		618		921		2,627		3,120

Total Electric Sales		14,401		15,012		41,411		42,241


Electric Deliveries
Retail and Wholesale		13,783		14,091		38,784		39,121
Electric Customer Choice		329		389		1,011		1,163
Electric Customer Choice — Self Generators (2)		—		180		70		447

Total Electric Sales and Deliveries		14,112		14,660		39,865		40,731


(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 $94 million in the third quarter of 2008 and $95 million in the nine-month period ended September 30, 2008. The decrease for the third quarter was primarily due to lower storm expenses of $13 million, $26 million of information systems implementation costs, lower benefits expense of $12 million, lower corporate support expenses of $15 million, lower fossil generation outage expenses of $10 million and $12 million attributable to continuous improvement initiatives. The decrease in the nine-month period was due primarily to $60 million of information systems implementation costs, lower benefit expenses of $35 million, lower corporate support expenses of $25 million, lower fossil generation outage expenses of $10 million, partially offset by higher uncollectible expenses of $31 million.

Depreciation and amortization expense decreased $10 million in the third quarter of 2008 and $20 million in the nine-month period ended September 30, 2008 due primarily to decreased amortization of regulatory assets.

Taxes other than income decreased $9 million in the third quarter of 2008 and $28 million in the nine-month period ended September 30, 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.

Other asset (gains) losses and reserves, net decreased $7 million and $13 million in the third quarter and nine-month period ended September 30, 2008 due to $6 million and $12 million reserve adjustments in the 2007 comparable periods for a loan guaranty related to our former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).

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 passed by the Michigan House of Representatives and Michigan Senate and signed by the Governor of Michigan, discussed more fully in the Overview section. Looking forward, additional issues, such as volatility in prices for coal and other commodities, 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.

Long term, we will be required to invest an estimated $2.4 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 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 License Application with the NRC for construction and operation of a possible 1,500 megawatt 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:

	•		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;

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

	•		Collectibility of accounts receivable;

	•		Weather, including the severity and frequency of storms;

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

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

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

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

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Factors impacting income: Gas Utility’s net loss decreased $14 million in the third quarter of 2008 due to higher gross margins and lower operation and maintenance expenses. Net income was higher by $2 million in the 2008 nine-month period due primarily to higher gross margins, partially offset by higher expenses for operation and maintenance, and depreciation and amortization.


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Operating Revenues	$	225		$	173		$	1,537		$	1,358
Cost of Gas		105			59			975			844

Gross Margin		120			114			562			514
Operation and Maintenance		94			106			365			330
Depreciation and Amortization		25			24			75			69
Taxes Other Than Income		9			14			35			43
Other Asset (Gains) Losses, Net		(2	)		(1	)		(2	)		2

Operating Income (Loss)		(6	)		(29	)		89			70


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Other (Income) and Deductions		15			10			40			28
Income Tax Provision (Benefit)		(6	)		(10	)		16			11

Net Income (Loss)	$	(15	)	$	(29	)	$	33		$	31


Operating Income as a Percentage of Operating Revenues		(3	)%		(17	)%		6	%		5	%

Gross margin increased $6 million in the third quarter of 2008 and $48 million in the nine-month period ended September 30, 2008. The increase in the third quarter is due primarily to higher revenue of $6 million associated with the uncollectible tracking mechanism, $2 million of appliance repair revenue and $1 million favorable impact of weather, partially offset by $4 million of lower storage services and $2 million of customer conservation and lower volumes. The increase in the nine-month period is due primarily to higher revenue of $39 million associated with the uncollectible tracking mechanism, $11 million favorable impact of lower lost gas recognized and higher valued gas received as compensation for transportation of third party customer gas, $4 million of appliance repair revenue and $3 million favorable impact of weather, partially offset by $7 million of lower storage services and $3 million as a result of customer conservation and lower volumes. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism. See Note 6 of the Notes to Consolidated Financial Statements.


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2008		2007		2008		2007
Gas Markets (in Millions)
Gas sales	$	156	$	106	$	1,297	$	1,118
End user transportation		22		21		105		101

		178		127		1,402		1,219
Intermediate transportation		18		12		53		42
Storage and other		29		34		82		97

	$	225	$	173	$	1,537	$	1,358


Gas Markets (in Bcf)
Gas sales		9		11		99		103
End user transportation		23		25		90		97

		32		36		189		200
Intermediate transportation		94		85		332		307

		126		121		521		507

Operation and maintenance expense decreased $12 million in the third quarter of 2008 and increased $35 million in the nine-month period ended September 30, 2008. The third quarter decrease is primarily due to $7 million of lower corporate support expenses, 2007 EBS costs of $3 million and lower benefits expenses of $5 million, partially offset by higher uncollectible expenses of $4 million. The increase in the 2008 nine-month period is due primarily to higher uncollectible expenses of $52 million, partially offset by $19 million of lower corporate support expenses. The increase in uncollectible expense is partially offset by increased revenues from the uncollectible tracking mechanism included in gross margin discussed above.

Depreciation and amortization expense increased $1 million in the third quarter of 2008 and $6 million in the nine-month period ended September 30, 2008 due to higher levels of depreciable plant. In the nine-month period ended September 30, 2007, we recorded a $3 million adjustment resulting from an MPSC order related to pipeline assets.

Other asset (gains) losses, net improved by $4 million in the nine-month period ended September 30, 2008. In 2007, we recorded a $3 million loss attributable to an MPSC disallowance of certain costs related to the acquisition of pipeline assets.

Outlook —Higher gas prices and 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, remove waste and decrease our costs while improving customer satisfaction.

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

	•		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;

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

	•		Collectibility of accounts receivable;

	•		Weather;

	•		Customer conservation;

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

	•		Timing of base gas sales;

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

	•		Instability in capital markets which could impact availability of short and long-term financing.

NON-UTILITY OPERATIONS

Gas Midstream

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

Factors impacting income: Increased storage contract revenues and higher pipeline equity earnings offset by a non-recurring 2007 gain in the nine-month period and a higher tax provision due to the MBT in 2008, resulted in $2 million increases in net income in 2008 as compared to 2007. Operating revenues in the three and nine-month periods were higher due primarily to increased storage capacity sold in long-term agreements.


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Operating Revenues	$	19		$	16		$	53		$	49
Operation and Maintenance		3			3			10			9
Depreciation and Amortization		1			1			4			4
Taxes Other Than Income		1			1			2			2
Other Asset (Gains)Losses, net		—			—			—			(1	)

Operating Income		14			11			37			35
Other (Income) and Deductions		(4	)		(3	)		(9	)		(5	)
Income Tax Provision		7			5			19			15

Net Income	$	11		$	9		$	27		$	25

Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, an additional 7 Bcf of increased 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 1, 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. Gas Midstream has a 26% ownership interest in Millennium Pipeline which commenced construction in June 2007 and is scheduled to be in service in late 2008. There are certain substantive penalties to Millennium that potentially could be imposed in the event that completion is delayed after January 1, 2009. Millennium Pipeline 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 primarily 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 $1.3 billion.

In 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 ($82 million after-tax) on the sale in 2008.

Factors impacting income: The 2007 results reflect the recording of $323 million of losses on financial contracts related to expected Antrim gas production and sales through 2013. The 2008 nine-month 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.


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2008		2007		2008			2007
Operating Revenues	$	14	$	15	$	37		$	(244	)
Operation and Maintenance		5		5		16			30
Depreciation, Depletion and Amortization		2		4		7			18
Taxes Other Than Income		—		1		—			8
Other Asset (Gains) and Losses, net		—		—		(128	)		9

Operating Income (Loss)		7		5		142			(309	)
Other (Income) and Deductions		2		4		3			11
Income Tax Provision (Benefit)		2		—		50			(112	)

Net Income (Loss)	$	3	$	1	$	89		$	(208	)

Operating revenues decreased $1 million in the third quarter of 2008 and increased $281 million in the 2008 nine-month period. The improvement in the nine-month period reflects the recording of $323 million of losses during the 2007 periods 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. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions. In conjunction with the Antrim sale and effective settlement of these contract positions, Antrim reclassified amounts held in accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in the 2007 period by $323 million. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $1 million and $42 million in the three and nine months ended September 30, 2008 as compared to the same periods in 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.

Operation and maintenance expense was unchanged in the third quarter and decreased $14 million in the nine-month period ended September 30, 2008. For the nine-month period ended September 30, 2008, Barnett shale production was approximately 3.4 Bcfe compared with approximately 5.7 Bcfe during the same period in 2007, as a result of our monetization initiatives.

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 $80 million in the Barnett shale for the first nine months of 2008 and expect to invest an additional $15 million during the remainder of the year. During 2008, we expect to drill 35 new wells and achieve Barnett shale production of approximately 5 Bcfe of natural gas from our remaining properties, compared with approximately 7.7 Bcfe in 2007 from all properties, including those that were sold.

Power and Industrial Projects

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 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 increased by $17 million in the 2008 third quarter and $4 million for the nine-month period ended September 30, 2008. This is primarily due to lower operations and maintenance expenses, partially offset by lower revenues.


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Operating Revenues	$	264		$	298		$	778		$	972
Operation and Maintenance		223			276			707			904
Depreciation and Amortization		12			13			23			33
Taxes Other Than Income		3			2			10			9
Asset (Gains) Losses, Net		(4	)		(1	)		9			(1	)

Operating Income		30			8			29			27
Other (Income) and Deductions		(12	)		(1	)		(15	)		8
Minority Interest		3			(1	)		4			(4	)
Income Taxes
Provision		15			3			16			6
Production Tax Credits		(2	)		(2	)		(6	)		(9	)

		13			1			10			(3	)

Net Income	$	26		$	9		$	30		$	26

Operating revenues decreased $34 million in the third quarter of 2008 and $194 million in the nine-month period ended September 30, 2008. The third quarter decline is primarily due to a reduction in coal transportation and trading volumes and a customer purchasing change that resulted in coal being sourced directly from the supplier. These factors were offset by higher incremental coke sales and a favorable mark-to-market valuation. The 2008 nine- month decrease was primarily attributable to reductions in coal transportation and trading volumes, and the customer purchasing change.

Operation and maintenance expense decreased $53 million in the third quarter of 2008 and $197 million in the nine-month period ended September 30, 2008. These decreases reflect the lower coal transportation volumes affecting operating revenues combined with a reduction in coal trading volumes.

Other Assets (gains) losses, net expense improved by $3 million in the third quarter of 2008 and decreased $10 million in the nine-month period ended September 30, 2008. The nine-month loss 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. The increase in gains for the 2008 quarter and an offset to the nine month period loss were gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production.

Other (income) and deductions were higher by $11 million in the third quarter and $23 million higher in the nine-month period due primarily to an adjustment to inter-company interest allocation with Corporate & Other (which eliminates in consolidation).

Outlook — Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We expect to see a positive impact on net income through the rest of 2008, offset by approximately $11 million of our annual 2007 coal transportation and marketing business net income. This activity was dependent upon our Synfuel operations that ceased operations at the end of 2007.

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 pipelines and storage, and power transmission and generating capacity positions.

Factors impacting income: Energy Trading’s 2008 third quarter net income was lower by $26 million. Net income increased $3 million in the nine-month period ended September 30, 2008.


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2008		2007		2008		2007
Operating Revenues	$	405	$	292	$	1,128	$	700
Fuel, Purchased Power and Gas		355		203		1,004		599

Gross Margin		50		89		124		101
Operation and Maintenance		17		17		50		41
Depreciation, Depletion and Amortization		1		1		4		3
Taxes Other Than Income		1		—		2		1

Operating Income		31		71		68		56
Other (Income) and Deductions		—		3		3		6
Income Tax Provision		12		23		29		17

Net Income	$	19	$	45	$	36	$	33

Gross margin decreased $39 million in the third quarter of 2008 and increased $23 million in the nine-month period ended September 30, 2008.

The third quarter 2008 decrease is comprised of unfavorable unrealized and realized margins of $29 million and $10 million, respectively. The decrease in unrealized margins consisted of $49 million unfavorability in our power marketing, transmission optimization, and full requirements wholesale portfolios, and $9 million in our oil portfolio due to timing related gains in 2007. This unfavorability is partially offset by $29 million mark-to-market increases largely in our gas storage strategies resulting from impact of forward gas prices. The decrease in realized margins consisted of $19 million and $4 million from our power and oil strategies, respectively, partially offset by $13 million improvement in realized margins from our gas strategies. Realized increases in our gas strategies were due to the impact of declining gas prices on recurring long-term gas contracts and favorability resulting from a $9 million gain from the termination of a long-term physical sales contract, partially offset by an $18 million lower of cost or market adjustment for inventory in 2008.

The increase for the nine-month period is due to higher unrealized margins of $18 million and improved realized margins of $5 million. The increase in unrealized margins includes the absence of $30 million in mark-to-market losses in June 2007 reflecting revisions of valuation estimates for natural gas contracts. Partially offsetting this favorability is the absence of $14 million of prior year mark to market timing related gains in our oil portfolio. Higher realized margins consisted of $33 million from our gas strategies, primarily gas trading, and $3 million from our oil trading portfolio, partially offset by $31 million decline in power positions, primarily from our power marketing and transmission optimization strategies.

Operation and maintenance expense was unchanged in the third quarter of 2008 and increased $9 million in the nine-month period ended September 30, 2008 due to higher payroll and incentive costs.

Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage, natural gas pipelines, and power transmission and full requirements contracts. The financial instruments are deemed derivatives, whereas the proprietary gas inventory, pipelines, transmission contracts, certain full requirements contracts and 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 assets. The majority 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. Energy Trading’s strategy is to economically manage the price risk of storage with futures and over-the-counter forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.

See also the “Fair Value” section that follows.

CORPORATE & OTHER

Corporate & Other results include various corporate staff functions that support the entire Company. Their associated costs are fully allocated to the various segments based on services utilized. As a result, the allocation amount can vary from year to year on each segment. In addition, Corporate & Other holds certain non-utility debt and energy related investments.

Factors impacting income: Corporate & Other results were lower by $44 million in the third quarter of 2008 and $551 million in the 2008 nine-month period, due primarily to the 2007 gain on the sale of the Antrim shale gas exploration and production business of approximately $897 million ($574 million after-tax) and an adjustment to inter-company interest allocation with Power and Industrial Projects (which eliminates in consolidation), partially offset by effective income tax rate adjustments.

DISCONTINUED OPERATIONS

Synthetic Fuel

We discontinued the operations of our synthetic fuel production facilities throughout the United States 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 substantially offset by production tax credits.

The incentive provided by production tax credits was designed to reduce and phase out if the price of oil increased to the point of providing significant market incentives for the production of synthetic fuels. As such, the tax credit in a given year was phased out if the reference price of oil within that year exceeded a threshold price. As of December 31, 2007, the reference price exceeded the threshold and the tax credit value was reduced by an estimated phase-out percentage of 69%. Reserves for expected refunds of partner payments for production tax credits were recorded at December 31, 2007 based on this estimated phase-out percentage. A $12 million pre-tax gain was recorded in the first quarter of 2008 to reflect the actual 67% phase-out percentage based on the actual IRS Reference Price and inflation factor published by the IRS in March 2008. In the third quarter of 2008, an additional pre-tax gain of $16 million was recorded to recognize a true-up of final payments and distributions to partners.


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2008		2007		2008		2007
Operating Revenues	$	—	$	277	$	7	$	806
Operation and Maintenance		—		329		9		967


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Depreciation and Amortization		—			1			(2	)		4
Taxes Other Than Income		—			(5	)		(1	)		3
Asset (Gains), Losses and Reserves, Net		(16	)		(67	)		(31	)		(144	)

Operating Income (Loss)		16			19			32			(24	)
Other (Income) and Deductions		(1	)		(1	)		(3	)		(7	)
Minority Interest		—			(46	)		2			(161	)
Income Taxes
Provision		9			22			14			49
Production Tax Credits		—			(1	)		(1	)		(25	)

		9			21			13			24

Net Income	$	8		$	45		$	20		$	120

Operating revenues decreased $277 million in the third quarter of 2008 and $799 million for the nine-month period ended September 30, 2008 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.

Operation and maintenance expense decreased $329 million in the third quarter of 2008 and $958 million in the nine-month period ended September 30, 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 activity reflects adjustments to 2007 contractually defined cost sharing mechanisms with suppliers, as determined by applying the actual phase-out percentage.

Asset (gains), losses and reserves, net decreased $51 million in the third quarter of 2008 and $113 million in the nine-month period ended September 30, 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 activity reflects the impact of reserve adjustments for the final phase-out percentage and true-ups of final payments and distributions to partners.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES AND NEW ACCOUNTING PRONOUNCEMENTS

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.

See also Notes 2 and 3 of the Notes to Consolidated Financial Statements.

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 the first nine months of 2008, our cash requirements were met primarily through operations and from our non-utility monetization program. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.


	Nine Months Ended
	September 30
(in Millions)	2008			2007
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	417		$	716
Depreciation, depletion and amortization		675			716
Deferred income taxes		280			90
Gain on sale of non-utility assets		(128	)		(897	)
Gain on sale of synfuel and other assets, net		(19	)		(130	)
Working capital and other		(207	)		297

		1,018			792


	Nine Months Ended
	September 30
(in Millions)	2008			2007
Investing activities:
Plant and equipment expenditures — utility		(842	)		(750	)
Plant and equipment expenditures — non-utility		(154	)		(206	)
Proceeds from sale of non-utility assets		253			1,258
Proceeds (refunds) from sale of synfuels and other assets		(282	)		287
Restricted cash and other investments		(23	)		3

		(1,048	)		592


Financing activities:
Issuance of long-term debt		1,013			—
Redemption of long-term debt		(446	)		(340	)
Repurchase of long-term debt		(238	)		—
Short-term borrowings, net		71			(62	)
Repurchase of common stock		(16	)		(686	)
Dividends on common stock and other		(265	)		(280	)

		119			(1,368	)

Net Increase in Cash and Cash Equivalents	$	89		$	16

Cash from Operating Activities

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

Cash from operations in the nine months ended September 30, 2008 increased $226 million from the comparable 2007 period. The operating cash flow increase 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 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. Net cash used for investing activities was approximately $1 billion for the nine months ended September 30, 2008, compared with cash from investing activities of $592 million in the same period in 2007. The change was primarily driven by our non-utility monetization program and the completion of refund payments to our synfuel partners in 2008.

Cash from Financing Activities

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

Net cash from financing activities was $119 million during the nine months ended September 30, 2008 compared to net cash used for financing activities of approximately $1.4 billion for the same period in 2007. The change was primarily attributable to increased proceeds from the issuance of long-term debt and lower repurchases of common stock.

Outlook

We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We have incurred costs associated with implementation of our Performance Excellence Process, but we began to realize sustained net cost savings in 2007. We may also 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.

We anticipate approximately $200 million of net synfuel-related cash impacts in 2008 and 2009, which consists of the final reconciliation of cash from synthetic fuel operations (related to activity prior to December 31, 2007), proceeds from option hedges, and tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments.

As part of a strategic review of our non-utility operations, we have taken various actions including the sale, restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and an additional approximately $170 million in the first nine months of 2008 from the sale of a portion of Barnett shale properties. Proceeds from the monetization activities were used to repurchase common stock and redeem outstanding debt.

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.

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. 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 during the first nine months of 2008.

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 future periods. 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 in late September, access to the commercial paper markets has been sharply reduced and, as a result, we have drawn 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 Detroit Edison’s issuance of $250 million of five-year senior notes in October 2008. See Note 1 of the Notes to Consolidated Financial Statements.

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 are expected to have a negative return for 2008, which would create increased benefit costs in future years and may result in higher contributions in future years than originally planned.

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.

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 3 of the Notes to Consolidated Financial Statements.

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 Assets or Liabilities from risk management and trading activities, 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 permit us to record gains 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 third quarter and nine months ended September 30, 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 (and which are therefore excluded from the following tables) 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 gas reserves. A portion of the price risk associated with anticipated production from the Barnett gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Assets or Liabilities from risk management and trading activities, 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 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 table provides details on changes in our MTM net asset (or liability) position for the nine months ended September 30, 2008:


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

Reclassify to realized upon settlement		18			(283	)		72			(1	)		(194	)
Changes in fair value recorded to income		(24	)		333			11			(13	)		307
Amortization of option premiums		—			(1	)		(1	)		—			(2	)

Amounts recorded to unrealized income		(6	)		49			82			(14	)		111
Cumulative effect adjustment to initially apply SFAS No. 157, pre-tax		—			7			—			—			7
Amounts recorded in other comprehensive income		—			—			—			—			—
Change in collateral held by (for) others		2			17			(33	)		—			(14	)
Option premiums paid and other		—			9			(10	)		—			(1	)

MTM at September 30, 2008	$	—		$	(283	)	$	47		$	(12	)	$	(248	)

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 “Assets and Liabilities from risk management and trading activities,” as reflected on the Consolidated Statements of Financial Position as of September 30, 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
(in Millions)	Hedges			Contracts			Trading			Eliminations			Other			(Liabilities)
Current assets	$	20		$	192		$	121		$	(7	)	$	5		$	331
Noncurrent assets		2			173			34			(3	)		—			206

Total MTM assets		22			365			155			(10	)		5			537


Current liabilities		(17	)		(293	)		(92	)		7			(16	)		(411	)
Noncurrent liabilities		(5	)		(355	)		(16	)		3			(1	)		(374	)

Total MTM liabilities		(22	)		(648	)		(108	)		10			(17	)		(785	)


Total MTM net assets (liabilities)	$	—		$	(283	)	$	47		$	—		$	(12	)	$	248

The table below shows the maturity of our MTM positions:


										2011
(in Millions)										and			Total Fair
Source of Fair Value	2008			2009			2010			Beyond			Value
Economic Hedges	$	(4	)	$	10		$	(6	)	$	—		$	—
Structured Contracts		(25	)		(104	)		(45	)		(109	)		(283	)
Proprietary Trading		(1	)		54			(6	)		—			47
Other		—			(6	)		(5	)		(1	)		(12	)

Total	$	(30	)	$	(46	)	$	(62	)	$	(110	)	$	(248	)

Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

The Electric and Gas utility businesses have risks in connection with the anticipated purchases of coal, natural gas, uranium, electricity and base metals to meet their service obligations. However, the Company does not bear material exposure to earnings risk as such changes are included in regulatory rate recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs. See Note 6 of the Notes to Consolidated Financial Statements.

The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery. DTE manages this risk through timely regulatory filings, interim rate relief proceedings, tracking mechanisms and long-term supply contracts, where possible.

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

Our Unconventional Gas Production business segment has exposure to natural gas and crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure, we may use forward energy contracts and swaps. Approximately 45% of the 2008 production is hedged.

Our Power and Industrial Projects segment is subject to electricity, natural gas, petroleum- based chemical and coal-based product price risk. To manage this exposure, we may use forward energy, capacity and futures contracts.

Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil and foreign currency price fluctuations. These risks are managed through its energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts.

Credit Risk

Bankruptcies

We transact with numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U. S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our previously accrued amounts are adequate for probable loss. The final resolution of these matters is not expected to have a material effect on our financial statements.

Other

We engage in business with customers that are both investment and non-investment grade. We closely monitor the credit ratings of all our customers and, when allowable and deemed necessary, we request collateral or guarantees from such customers to secure their obligations above a predetermined credit exposure limit.

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of September 30, 2008:


	Credit Exposure
	before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade (1)
A- and Greater	$	267	$	(6	)	$	261
BBB+ and BBB		138		—			138
BBB-		66		—			66

Total Investment Grade		471		(6	)		465
Non-investment grade (2)		105		(5	)		100
Internally Rated — investment grade (3)		182		(2	)		180
Internally Rated — non-investment grade (4)		17		(9	)		8

Total	$	775	$	(22	)	$	753


(1)		This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investors Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 47% of the total gross credit exposure.

(2)		This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented approximately 13% of the total gross credit exposure.

(3)		This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 7% of the total gross credit exposure.

(4)		This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 1% of the total gross credit exposure.

Interest Rate Risk

We are subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of September 30, 2008, we had a floating rate debt-to-total debt ratio of approximately 17.4% (excluding securitized debt).

Foreign Currency Risk

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

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at September 30, 2008 by a hypothetical 10% and calculating the resulting change in the fair values. The following represents the results of the sensitivity analysis calculations:


(in Millions)	Assuming a 10%			Assuming a 10%
Activity	increase in rates			decrease in rates			Change in the fair value of
Coal Contracts	$	1		$	(1	)	Commodity contracts
Gas Contracts	$	(17	)	$	18		Commodity contracts
Oil Contracts	$	1		$	(1	)	Commodity contracts
Power Contracts	$	6		$	(6	)	Commodity contracts
Interest Rate Risk	$	(306	)	$	335		Long-term debt
Foreign Currency Risk	$	(12	)	$	12		Forward contracts

Part I — Item 4.

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) as of September 30, 2008, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part I — Item 1.

DTE Energy Company

Consolidated Statements of Operations (Unaudited)


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions, Except per Share Amounts)	2008			2007			2008			2007
Operating Revenues	$	2,338		$	2,128		$	7,159		$	6,267


Operating Expenses
Fuel, purchased power and gas		1,034			763			3,332			2,596
Operation and maintenance		628			752			2,081			2,282
Depreciation, depletion and amortization		235			248			677			712
Taxes other than income		71			76			229			276
Gain on sale of non-utility assets		—			—			(128	)		(897	)
Other asset (gains) losses, reserves and impairments, net		(5	)		3			7			22

		1,963			1,842			6,198			4,991


Operating Income		375			286			961			1,276


Other (Income) and Deductions
Interest expense		125			131			371			401
Interest income		(5	)		(10	)		(13	)		(24	)
Other income		(34	)		(27	)		(74	)		(51	)
Other expenses		22			5			45			23

		108			99			329			349


Income Before Income Taxes and Minority Interest		267			187			632			927

Income Tax Provision		97			34			231			328

Minority Interest		1			1			4			3


Income from Continuing Operations		169			152			397			596

Discontinued Operations
Income (loss) from discontinued operations, net of tax		8			(1	)		22			(41	)
Minority interest in discontinued operations		—			(46	)		2			(161	)

		8			45			20			120

Net Income	$	177		$	197		$	417		$	716


Basic Earnings per Common Share
Income from continuing operations	$	1.04		$	0.93		$	2.45		$	3.47
Discontinued operations		0.05			0.27			0.12			0.70

Total	$	1.09		$	1.20		$	2.57		$	4.17


Diluted Earnings per Common Share
Income from continuing operations	$	1.03		$	0.92		$	2.44		$	3.46
Discontinued operations		0.05			0.27			0.12			0.69

Total	$	1.08		$	1.19		$	2.56		$	4.15


Weighted Average Common Shares Outstanding
Basic		162			165			162			172
Diluted		163			166			163			173
Dividends Declared per Common Share	$	0.53		$	0.53		$	1.59		$	1.59

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)


	September 30			December 31
(in Millions)	2008			2007
ASSETS
Current Assets
Cash and cash equivalents	$	223		$	123
Restricted cash		36			140
Accounts receivable (less allowance for doubtful accounts of $266 and $182, respectively)
Customer		1,375			1,658
Other		320			514
Accrued power and gas supply cost recovery revenue		110			76
Inventories
Fuel and gas		564			429
Materials and supplies		206			204
Deferred income taxes		259			387
Assets from risk management and trading activities		331			181
Other		299			196
Current assets held for sale		—			83

		3,723			3,991


Investments
Nuclear decommissioning trust funds		756			824
Other		538			446

		1,294			1,270


Property
Property, plant and equipment		19,907			18,809
Less accumulated depreciation and depletion		(7,837	)		(7,401	)

		12,070			11,408


Other Assets
Goodwill		2,037			2,037
Regulatory assets		2,830			2,786
Securitized regulatory assets		1,035			1,124
Intangible assets		86			25
Notes receivable		114			87
Assets from risk management and trading activities		206			199
Prepaid pension assets		167			152
Other		126			116
Noncurrent assets held for sale		—			547

		6,601			7,073


Total Assets	$	23,688		$	23,742

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)


	September 30			December 31
(in Millions, Except Shares)	2008			2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	931		$	1,189
Accrued interest		138			112
Dividends payable		87			87
Short-term borrowings		1,155			1,084
Current portion long-term debt, including capital leases		362			454
Liabilities from risk management and trading activities		411			281
Deferred gains and reserves		4			400
Other		505			566
Current liabilities associated with assets held for sale		—			48

		3,593			4,221


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		6,158			5,576
Securitization bonds		933			1,065
Trust preferred-linked securities		289			289
Capital lease obligations		64			41

		7,444			6,971


Other Liabilities
Deferred income taxes		1,951			1,824
Regulatory liabilities		1,168			1,168
Asset retirement obligations		1,325			1,277
Unamortized investment tax credit		99			108
Liabilities from risk management and trading activities		374			450
Liabilities from transportation and storage contracts		115			126
Accrued pension liability		68			68
Accrued postretirement liability		1,063			1,094
Deferred gains		12			15
Nuclear decommissioning		122			134
Other		313			303
Noncurrent liabilities associated with assets held for sale		—			82

		6,610			6,649


Commitments and Contingencies (Notes 2, 6 and 9)

Minority Interest		45			48


Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 163,025,446 and 163,232,095 shares issued and outstanding, respectively		3,172			3,176
Retained earnings		2,952			2,790
Accumulated other comprehensive loss		(128	)		(113	)

		5,996			5,853


Total Liabilities and Shareholders’ Equity	$	23,688		$	23,742

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended
	September 30
(in Millions)	2008			2007
Operating Activities
Net income	$	417		$	716
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		675			716
Deferred income taxes		280			90
Gain on sale of non-utility assets		(128	)		(897	)
Other asset (gains), losses and reserves, net		12			14
Gain on sale of interests in synfuel projects		(31	)		(144	)
Partners’ share of synfuel project (gains) losses		2			(161	)
Contributions from synfuel partners		14			177
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(223	)		281

Net cash from operating activities		1,018			792


Investing Activities
Plant and equipment expenditures — utility		(842	)		(750	)
Plant and equipment expenditures — non-utility		(154	)		(206	)
Proceeds from sale of interests in synfuel projects		84			329
Refunds to synfuel partners		(387	)		(81	)
Proceeds from sale of non-utility assets		253			1,258
Proceeds from sale of other assets, net		21			39
Restricted cash for debt redemptions		104			52
Proceeds from sale of nuclear decommissioning trust fund assets		180			227
Investment in nuclear decommissioning trust funds		(202	)		(254	)
Other investments		(105	)		(22	)

Net cash from (used for) investing activities		(1,048	)		592


Financing Activities
Issuance of long-term debt		1,013			—
Redemption of long-term debt		(446	)		(340	)
Repurchase of long-term debt		(238	)		—
Short-term borrowings, net		71			(62	)
Repurchase of common stock		(16	)		(686	)
Dividends on common stock		(258	)		(278	)
Other		(7	)		(2	)

Net cash from (used for) financing activities		119			(1,368	)


Net Increase in Cash and Cash Equivalents		89			16
Cash and Cash Equivalents Reclassified (to) from Assets Held for Sale		11			(7	)
Cash and Cash Equivalents at Beginning of Period		123			147

Cash and Cash Equivalents at End of Period	$	223		$	156

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Changes in Shareholders’ Equity and

Comprehensive Income (Unaudited)


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

Balance, December 31, 2007		163,232		$	3,176		$	2,790		$	(113	)	$	5,853

Net income		—			—			417			—			417
Implementation of SFAS No. 157, net of taxes of $2		—			—			4			—			4
Dividends declared on common stock		—			—			(259	)		—			(259	)
Repurchase and retirement of common stock		(432	)		(16	)		—			—			(16	)
Net change in unrealized gains on derivatives, net of tax		—			—			—			2			2
Net change in unrealized losses on investments, net of tax		—			—			—			(17	)		(17	)
Stock-based compensation and other		225			12			—			—			12

Balance, September 30, 2008		163,025		$	3,172		$	2,952		$	(128	)	$	5,996

The following table displays other comprehensive income for the nine—month periods ended September 30:


(in Millions)	2008			2007
Net income	$	417		$	716

Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $- and $2, respectively		—			3

Net unrealized gains (losses) on derivatives:
Losses during the period, net of taxes of $- and $(76), respectively		(1	)		(141	)
Amounts reclassified to income, net of taxes of $2 and $125, respectively		3			232

		2			91


Net unrealized gains (losses) on investments:
Losses during the period, net of taxes of $(9) and $(2), respectively		(17	)		(3	)
Amounts reclassified to income, net of taxes of $- and $1, respectively		—			2

		(17	)		(1	)

Comprehensive income	$	402		$	809

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — GENERAL

The Company is a diversified energy company. It is the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. The Company also operates four energy-related non-utility segments with operations throughout the United States.

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2007 Annual Report on Form 10-K.

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

The Consolidated Financial Statements are unaudited, but include all adjustments necessary for a fair presentation of such financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2008.

Certain prior year amounts have been reclassified to reflect current year classifications.

Asset Retirement Obligations

The Company records asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations for gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate.

For the Company’s regulated operations, timing differences arise in the expense recognition of legal asset retirement costs that the Company is currently recovering in rates. The Company defers such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

A reconciliation of the asset retirement obligations for the nine months ended September 30, 2008 follows:


(in Millions)
Asset retirement obligations at January 1, 2008	$	1,293
Accretion		62
Liabilities settled		(15	)
Revision in estimated cash flows		(11	)
Transfers from Assets held for sale		14

Asset retirement obligations at September 30, 2008		1,343
Less amount included in current liabilities		(18	)

	$	1,325

Approximately $1 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear power plant.

Intangible Assets

The Company has certain intangible assets relating to non-utility contracts and emission allowances. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. The gross carrying amount and accumulated amortization of intangible assets at September 30, 2008 were $102 million and $16 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $31 million and $6 million, respectively. Amortization expense of intangible assets is estimated to be $5 million annually for the years 2008 through 2012.

Retirement Benefits and Trusteed Assets

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


							Other Postretirement
Three Months Ended September 30	Pension Benefits						Benefits
(in Millions)	2008			2007			2008			2007
Service cost	$	13		$	16		$	15		$	17
Interest cost		48			46			30			28
Expected return on plan assets		(64	)		(59	)		(19	)		(17	)
Amortization of:
Net actuarial loss		8			16			10			18
Prior service cost		1			2			(2	)		(1	)
Net transition liability		—			—			1			3
Special termination benefits		—			3			—			—

Net periodic benefit cost	$	6		$	24		$	35		$	48


							Other Postretirement
Nine Months Ended September 30	Pension Benefits						Benefits
(in Millions)	2008			2007			2008			2007
Service cost	$	41		$	47		$	46		$	47
Interest cost		143			134			91			89
Expected return on plan assets		(194	)		(179	)		(57	)		(50	)
Amortization of:
Net actuarial loss		24			44			29			51
Prior service cost		4			4			(5	)		(2	)
Net transition liability		—			—			2			5
Special termination benefits		—			8			—			2

Net periodic benefit cost	$	18		$	58		$	106		$	142

Special Termination Benefits in the above table represents costs associated with the Company’s Performance Excellence Process.

The Company expects to contribute $150 million to its qualified pension plans during its fiscal year 2008. No contributions have been made to the plans for the three- and nine- month periods ended September 30, 2008.

The Company expects to contribute $5 million to its non-qualified pension plans during its fiscal year 2008. No contributions have been made to the plans for the three- and nine- month periods ended September 30, 2008.

The Company expects to contribute $116 million to its postretirement medical and life insurance benefit plans during its fiscal year 2008. No contributions were made during the three-month period ended September 30, 2008. Approximately $40 million of contributions were made to the plans for the nine-month period ended September 30, 2008.

Income Taxes

The Company’s effective income tax rate from continuing operations for the three months ended September 30, 2008 was 37% as compared to 18% for the three months ended September 30, 2007, and for the nine months ended September 30, 2008 was 37% as compared to 35% for the nine months ended September 30, 2007. The 2008 third

quarter rate is higher due primarily to a lower interim effective tax rate in 2007. The 2008 effective tax rate increase is also due to higher state income taxes related to the Michigan Business Tax which was effective January 1, 2008.

The Company has $17 million of unrecognized tax benefits at September 30, 2008 as compared to $14 million of unrecognized tax benefits at December 31, 2007 that, if recognized, would favorably impact its effective tax rate. During the next 12 months, statutes of limitations will expire for the Company’s tax returns in various states, and it is reasonably possible that state tax audits will also be settled. It is therefore possible that there will be a decrease in unrecognized tax benefits of $6 million within the next 12 months.

Short-Term Credit Arrangements and Borrowings

DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year credit facilities are with a syndicate of banks and may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. Borrowings under the facilities are available at prevailing short-term interest rates. The agreements require the Company to maintain a debt to total capitalization ratio of no more than 0.65 to 1. In addition, Detroit Edison has a separate $100 million short-term unsecured bank loan facility with covenants identical to those specified under our back-up credit facilities. DTE Energy, Detroit Edison and MichCon are currently in compliance with this financial covenant. The availability under these combined facilities is shown in the following table:


(in Millions)	DTE Energy			Detroit Edison			MichCon			Total
Five-year unsecured revolving facility, expiring October 2010	$	675		$	69		$	181		$	925
Five-year unsecured revolving facility, expiring October 2009		525			206			244			975
Unsecured bank loan facility, expiring July 2009		—			100			—			100


Total credit facilities at September 30, 2008		1,200			375			425			2,000


Amounts outstanding at September 30, 2008:
Commercial paper issuances and borrowings		(381	)		(373	)		(401	)		(1,155	)
Letters of credit		(286	)		—			—			(286	)

		(667	)		(373	)		(401	)		(1,441	)

Net availability at September 30, 2008	$	533		$	2		$	24		$	559

At October 31, 2008, amounts outstanding totaled $1,349 million, resulting in net availability under these combined facilities of $651 million.

Stock-Based Compensation

The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units to employees and members of its Board of Directors.

The Company recorded stock-based compensation expense of $8 million and $8 million, with an associated tax benefit of $3 million and $2 million for the three months ended September 30, 2008 and 2007, respectively. The Company recorded stock-based compensation expense of $33 million and $27 million, with an associated tax benefit of $12 million and $9 million for the nine months ended September 30, 2008 and 2007, respectively. Compensation cost capitalized in property, plant and equipment was $0.4 million and $0.3 million during the three months ended September 30, 2008 and 2007, respectively. Compensation cost capitalized in property, plant and equipment was $1.4 million and $1.5 million during the nine months ended September 30, 2008 and 2007, respectively.

Stock Options

The following table summarizes our stock option activity for the nine months ended September 30, 2008:


						(in Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Options outstanding at January 1, 2008		4,394,809		$	42.37
Granted		811,300		$	41.77
Exercised		(65,097	)	$	33.67
Forfeited or expired		(78,967	)	$	44.09

Options outstanding at September 30, 2008		5,062,045		$	42.36	$	4


Options exercisable at September 30, 2008		3,808,654		$	42.04	$	4

As of September 30, 2008, the weighted average remaining contractual life for the exercisable shares was 4.67 years. As of September 30, 2008, 1,253,391 options were non-vested. During the nine months ended September 30, 2008, 610,440 options vested.

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


	Nine Months Ended
	September 30, 2008			September 30, 2007
Risk-free interest rate		3.05	%		4.71	%
Dividend yield		5.20	%		4.38	%
Expected volatility		20.45	%		17.99	%

Expected life	6 years			6 years

The weighted average grant date fair value of options granted during the nine months ended September 30, 2008 was $4.76 per share. The intrinsic value of options exercised for the nine months ended September 30, 2008 was $0.6 million. Total option expense recognized was $0.5 million and $0.7 million for the three months ended September 30, 2008 and 2007, respectively, while total option expense recognized was $3 million and $3 million for the nine months ended September 30, 2008 and 2007, respectively.

Stock Awards

The following summarizes stock awards activity for the nine months ended September 30, 2008:


				Weighted Average
	Restricted			Grant Date
	Stock			Fair Value
Balance at January 1, 2008		984,310		$	47.36
Grants		379,600			41.99
Forfeitures		(64,315	)		45.49
Vested		(365,678	)		46.90

Balance at September 30, 2008		933,917			45.37

Performance Share Awards

The following summarizes performance share activity for the nine months ended September 30, 2008:


	Performance Shares
Balance at January 1, 2008		1,174,153
Grants		534,965
Forfeitures		(67,025	)
Payouts		(312,647	)

Balance at September 30, 2008		1,329,446

Unrecognized Compensation Cost

As of September 30, 2008, the Company had $44 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. These costs are expected to be recognized over a weighted-average period of 1.15 years.

Consolidated Statement of Cash Flows

The following provides detail of the changes in assets and liabilities that are reported in the Consolidated Statement of Cash Flows, and supplementary cash information:


	Nine Months Ended
	September 30
(in Millions)	2008			2007
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	456		$	383
Accrued GCR revenue		(102	)		(37	)
Inventories		(134	)		(45	)
Accounts payable		(221	)		(176	)
Income taxes payable		(31	)		(112	)
Risk management and trading activities		(103	)		127
Deferred gains from asset sales		39			15
Postretirement obligation		(30	)		10
Other assets		(86	)		(358	)
Other liabilities		(11	)		474

	$	(223	)	$	281

Supplementary Cash Information
Cash paid for interest (net of interest capitalized)	$	345		$	392
Cash paid for income taxes	$	21		$	314

In connection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent. As a result, the Company entered into a demand financing agreement for up to $50 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). There were no balances outstanding under this facility at September 30, 2008 and approximately $13 million outstanding as of December 31, 2007.

Other Asset (Gains) and Losses, Reserves and Impairments, net

The following items are included in the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statement of Operations:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Electric utility	$	(1	)	$	6		$	(1	)	$	12
Gas utility		(2	)		(1	)		(2	)		2

		(3	)		5			(3	)		14

Non-utility:
Power and industrial projects		(4	)		(1	)		9			(1	)
Barnett shale		—			—			—			9
Other		2			(1	)		1			—

	$	(5	)	$	3		$	7		$	22

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Accounting

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Effective January 1, 2008, the Company adopted SFAS No. 157. As permitted by FASB Staff Position FAS No. 157-2, the Company has elected to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. See also Note 3.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This Statement permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items, for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. At January 1, 2008, the Company elected not to use the fair value option for financial assets and liabilities held at that date.

In October 2008, the FASB issued FASB Staff Position (FSP) 157-3, Determining the Fair Value of a Financial Asset in a Market That is Not Active. The FSP clarifies the application of SFAS No. 157, Fair Value Measurements, in an inactive market, and provides an illustrative example to demonstrate how the fair value of a financial asset is determined when the market for that financial asset is inactive. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of the FSP did not have a material impact on the Company’s consolidated financial statements.

Business Combinations

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish this, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is applied prospectively to business combinations entered into by the Company after January 1, 2009, with earlier adoption prohibited. The Company will apply the requirements of SFAS No. 141(R) to business combinations consummated after January 1, 2009.

GAAP Hierarchy

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements under GAAP. SFAS No. 162 is effective 60 days following the approval of the Public Company Accounting Oversight Board amendments to AU section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The Company will adopt SFAS No. 162 once effective. The adoption is not expected to have a material impact on its consolidated financial statements.

Useful Life of Intangible Assets

In May 2008, the FASB issued FSP 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. For a recognized intangible asset, an entity shall disclose information that enables users to assess the extent to which the expected future cash flows associated with the asset are affected by the entity’s intent and/or ability to renew or extend the arrangement. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. The FSP will not have a material impact on the Company’s consolidated financial statements.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities

In June 2008, the FASB issued FSP EITF 03-6-1, Determining Whether Instruments Granted in Share Based Payment Transactions are Participating Securities. This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in paragraphs 60 and 61 of FASB No. 128, Earnings Per Share. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. The Company is currently assessing the effects of this FSP on its EPS calculation.

Disclosures about Derivative Instruments and Guarantees

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This Statement requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company will adopt SFAS No. 161 on January 1, 2009.

In September 2008, the FASB issued FSP No. 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161. This FSP is intended to improve disclosures about credit derivatives by requiring more information about the potential adverse effects of changes in credit risk on the financial position, financial performance, and cash flows of the sellers of credit derivatives. This FSP also requires additional disclosures about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN 45 are effective for reporting periods ending after November 15, 2008. The FSP also clarifies that the disclosures required by SFAS No. 161 should be provided for any reporting period (annual or interim) beginning after November 15, 2008. The Company is still assessing the impact of these pronouncements on our disclosures, and will begin providing any additional required disclosures related to SFAS No. 133 and FIN 45 for the year ending December 31, 2008. Disclosures necessary under SFAS No. 161 will be made beginning with the quarter ending March 31, 2009.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial
Statements — an Amendment of ARB No. 51. This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented. The Company will adopt SFAS No. 160 as of January 1, 2009 and is currently assessing the effects of SFAS No. 160 on its consolidated financial statements.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FSP FIN 39-1, Amendment of FASB Interpretation No. 39. This FSP permits the Company to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, the Company is permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007. It is applied retrospectively by adjusting the financial statements for all periods presented. The Company adopted FSP FIN 39-1 as of January 1, 2008. At adoption, the Company chose to offset the collateral amounts against the fair value of derivative assets and liabilities, reducing both the Company’s total assets and total liabilities. The Company retrospectively reclassified certain assets and liabilities on the Consolidated Statement of Financial Position at December 31, 2007 as follows:


	As Previously		FSP FIN 39-1
(in Millions)	Reported		Adjustments			As Adjusted
Current Assets
Accounts receivable
Collateral held by others	$	56	$	(3	)	$	53
Other		448		13			461
Assets from risk management and trading activities		195		(14	)		181
Other Assets
Assets from risk management and trading activities		207		(8	)		199
Current Liabilities
Accounts payable		1,198		(9	)		1,189
Liabilities from risk management and trading activities		282		(1	)		281
Other Liabilities
Liabilities from risk management and trading activities		452		(2	)		450

NOTE 3 — FAIR VALUE

Effective January 1, 2008, the Company adopted SFAS No. 157. This Statement defines fair value, establishes a framework for measuring fair value and expands the disclosures about fair value measurements. The Company has elected the option to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the third quarter and nine months ended September 30, 2008. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

SFAS No. 157 establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. SFAS No. 157 requires that assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined by SFAS No. 157 as follows:

	•		Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.

	•		Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

	•		Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2008:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments⁽²⁾			September 30, 2008
Assets:
Nuclear decommissioning trusts	$	469		$	287		$	—		$	—		$	756
Employee benefit trust investments ⁽¹⁾		20			56			—			—			76
Derivative assets		362			2,138			476			(2,439	)		537

Total	$	851		$	2,481		$	476		$	(2,439	)	$	1,369

Liabilities:
Deferred compensation	$	—		$	(18	)	$	—		$	—		$	(18	)
Derivative liabilities		(371	)		(1,935	)		(870	)		2,391			(785	)

Total	$	(371	)	$	(1,953	)	$	(870	)	$	2,391		$	(803	)

Net Assets (Liabilities) at September 30, 2008	$	480		$	528		$	(394	)	$	(48	)	$	566


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

(2)		Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

The following table presents the fair value reconciliation of Level 3 derivative assets and liabilities measured at fair value on a recurring basis for the nine months ended September 30, 2008:


(in Millions)	Derivatives
Liability balance as of January 1, 2008 ⁽¹⁾	$	(366	)
Changes in fair value recorded in income		262
Changes in fair value recorded in other comprehensive income		(6	)
Purchases, issuances and settlements		(242	)
Transfers in/out of Level 3		(42	)

Liability balance as of September 30, 2008	$	(394	)

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2008	$	10


(1)		Balance as of January 1, 2008 includes a cumulative effect adjustment which represents an increase to beginning retained earnings related to Level 3 derivatives upon adoption of SFAS No. 157.

Net gains of $262 million related to Level 3 derivative assets and liabilities are reported in Operating Revenues for the nine months ended September 30, 2008 consistent with the Company’s accounting policy. Net gains of $45 million related to Level 1 and Level 2 derivative assets and liabilities, and the impact of netting, are also reported in Operating Revenues for the nine months ended September 30, 2008. Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

SFAS No. 157 provides for limited retrospective application, the net of which is recorded as an adjustment to beginning retained earnings in the period of adoption. As a result, the Company recorded a cumulative effect adjustment of $4 million, net of taxes, as an increase to beginning retained earnings as of January 1, 2008.

Nuclear Decommissioning Trusts

The trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trust fund investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued using quoted prices in actively traded markets. Non-exchange- traded fixed income securities are valued based upon quotations available from brokers or pricing services.

Employee Benefit Trust Investments

The employee benefit trust investments are invested in commingled funds and institutional mutual funds holding equity or fixed income securities. The commingled funds and institutional mutual funds which hold exchange-traded equity securities are valued using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services.

Deferred Compensation Liabilities

Deferred compensation plans allow eligible participants to defer a portion of their compensation. The participant is able to designate the investment of the deferred compensation to investments available under the 401(k) plan offered by the Company, although the Company does not actually purchase the investments. The deferred compensation liability is determined based upon the fair values of the mutual funds and equity securities designated in each participant’s account.

Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. Other derivatives contracts are valued based upon a variety of inputs including commodity market prices, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period. Derivative instruments are principally used in the Company’s Energy Trading segment.

NOTE 4 — DISPOSALS AND DISCONTINUED OPERATIONS

Sale of Antrim Shale Gas Exploration and Production Business

In June 2007, the Company sold its Antrim shale gas exploration and production business (Antrim) for gross proceeds of approximately $1.3 billion and recognized a pre-tax gain of $897 million ($574 million after-tax) during 2007. Prior to the sale, the operating results of Antrim were reflected in the Unconventional Gas Production segment.

The Antrim business is not presented as a discontinued operation due to continuation of cash flows related to the sale of a portion of Antrim’s natural gas production to Energy Trading under the terms of natural gas sales contracts that expire in 2010 and 2012. These continuing cash flows, while not significant to DTE Energy, are significant to Antrim and therefore meet the definition of continuing cash flows as described in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations.

Plan to Sell Interest in Certain Power and Industrial Projects

During the third quarter of 2007, the Company announced its 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 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, the Company’s 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. During the second quarter of 2008, the Company recorded a loss of $19 million related to the valuation adjustment for the cumulative depreciation and amortization not recorded during the held for sale period. The Consolidated Statement of Financial Position includes $28 million of minority interests in the Projects classified as held for sale as of December 31, 2007.

The following table presents the major classes of assets and liabilities of the Projects classified as held for sale at December 31, 2007:


	December 31,
(in Millions)	2007
Cash and cash equivalents	$	11
Accounts receivable (less allowance for doubtful accounts of $4)		65
Inventories		4
Other current assets		3

Total current assets held for sale		83


Investments		55
Property, plant and equipment, net of accumulated depreciation of $183		285
Intangible assets		38
Long-term notes receivable		46
Other noncurrent assets		1

Total noncurrent assets held for sale		425


Total assets held for sale	$	508


	December 31,
(in Millions)	2007
Accounts payable	$	38
Other current liabilities		10

Total current liabilities associated with assets held for sale		48


Long-term debt (including capital lease obligations of $31)		53
Asset retirement obligations		16
Other liabilities		13

Total noncurrent liabilities associated with assets held for sale		82


Total liabilities related to assets held for sale	$	130

Sale of Interest in Barnett Shale Properties

In 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $260 million. As of December 31, 2007, property, plant and equipment of approximately $122 million, net of approximately $14 million of accumulated depreciation and depletion, was classified as held for sale. The Company recognized a gain of $128 million ($82 million after-tax) on the sale during 2008.

Synthetic Fuel Business

The Company discontinued the operations of its 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 substantially offset by production tax credits.


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Operating Revenues	$	—		$	277		$	7		$	806
Operation and Maintenance		—			329			9			967
Depreciation, Depletion and Amortization		—			1			(2	)		4
Taxes Other Than Income		—			(5	)		(1	)		3
Asset (Gains), Losses and Reserves, Net		(16	)		(67	)		(31	)		(144	)

Operating Income (Loss)		16			19			32			(24	)
Other (Income) and Deductions		(1	)		(1	)		(3	)		(7	)
Minority Interest		—			(46	)		2			(161	)
Income Taxes
Provision		9			22			14			49
Production Tax Credits		—			(1	)		(1	)		(25	)

		9			21			13			24

Net Income	$	8		$	45		$	20		$	120

NOTE 5 — RESTRUCTURING

In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process and began a series of focused improvement initiatives within its Electric and Gas Utilities, and the related corporate support functions. This process continued as of September 30, 2008.

The Company incurred costs to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. Pursuant to MPSC authorization, beginning in the third quarter of 2006, Detroit Edison deferred approximately $102 million of CTA in 2006. During 2007, Detroit Edison deferred CTA costs of $54 million. Detroit Edison began amortizing deferred 2006 costs in 2007 and 2007 deferred costs in 2008 as the recovery of these costs was provided for by the MPSC. Amortization of prior year deferred CTA costs was $4 million and $3 million for the three months ended September 30, 2008 and 2007, respectively, and $12

million and $8 million for the nine months ended September 30, 2008 and 2007, respectively. Detroit Edison deferred approximately $9 million and $18 million of CTA for the three months ended September 30, 2008 and 2007, respectively, and approximately $20 million and $39 million of CTA for the nine months ended September 30, 2008 and 2007, respectively. MichCon cannot defer CTA costs because a recovery mechanism has not been established. MichCon plans to seek a recovery mechanism in its next rate case which is expected to be filed in 2009. See Note 6.

Amounts expensed are recorded in Operation and maintenance on the Consolidated Statements of Operations. Deferred amounts are recorded in the Regulatory assets line on the Consolidated Statements of Financial Position. Costs incurred for the three- and nine-month periods ended September 30, 2008 and 2007 are as follows:


Three Months Ended September 30	Employee Severance Costs				Other Costs				Total Cost
(in Millions)	2008		2007		2008		2007		2008		2007
Costs incurred:
Electric Utility	$	—	$	3	$	9	$	16	$	9	$	19
Gas Utility		—		1		2		1		2		2
Other		—		—		2		—		2		—

Total costs		—		4		13		17		13		21
Less amounts deferred or capitalized:
Electric Utility		—		3		9		16		9		19

Amount expensed	$	—	$	1	$	4	$	1	$	4	$	2


Nine Months Ended September 30	Employee Severance Costs				Other Costs				Total Cost
(in Millions)	2008		2007		2008		2007		2008		2007
Costs incurred:
Electric Utility	$	—	$	14	$	21	$	30	$	21	$	44
Gas Utility		—		3		5		2		5		5
Other		—		1		3		—		3		1

Total costs		—		18		29		32		29		50
Less amounts deferred or capitalized:
Electric Utility		—		14		21		30		21		44

Amount expensed	$	—	$	4	$	8	$	2	$	8	$	6

NOTE 6 — REGULATORY MATTERS

Regulation

Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates and recovery of certain costs. These costs include the costs of generating facilities, regulatory assets, conditions of service, accounting, and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.

MPSC Show-Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reduced in 2007. Subsequently, Detroit Edison filed its response to this order and the MPSC issued an
order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

As part of the settlement agreement, a Choice Incentive Mechanism (CIM) was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. If electric Customer Choice sales exceed

3,600 GWh, Detroit Edison will be able to recover 90% of its reduction in non-fuel revenue from full service customers, up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100% of the increase in non-fuel revenue to the unrecovered regulatory asset balance. In March 2008, Detroit Edison filed a reconciliation of its CIM for the year 2007. Detroit Edison’s annual Electric Choice sales for 2007 were 2,239 GWh which was below the base level of sales of 3,200 GWh. Accordingly, the Company used the resulting additional non-fuel revenue to reduce unrecovered regulatory asset balances related to the Regulatory Asset Recovery Surcharge (RARS) mechanism. This reconciliation did not result in any rate increase.

2007 Electric Rate Case Filing

Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing with the MPSC requested a $123 million, or 2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008.

The requested $123 million increase in revenues is required to recover significant environmental compliance costs and inflationary increases, partially offset by net savings associated with the Performance Excellence Process. The filing was based on a return on equity of 11.25% on an expected 50% capital and 50% debt capital structure by the end of 2008.

In addition, Detroit Edison’s filing made, among other requests, the following proposals:

	•		Make progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;

	•		Equalize distribution rates between Detroit Edison full service and Customer Choice customers;

	•		Re-establish with modification the CIM originally established in the Detroit Edison 2006 show cause filing. The CIM reconciles changes related to customers moving between Detroit Edison full service and electric Customer Choice;

	•		Terminate the Pension Equalization Mechanism;

	•		Establish an emission allowance pre-purchase plan to ensure that adequate emission allowances will be available for environmental compliance; and

	•		Establish a methodology for recovery of the costs associated with preparation of an application for a new nuclear generation facility.

Also in the filing, in connection with Michigan’s 21st Century Energy Plan, Detroit Edison reinstated a long-term integrated resource planning (IRP) process with the purpose of developing the least overall cost plan to serve customers’ generation needs over the next 20 years. Based on the IRP, new base load capacity may be required for Detroit Edison. To protect tax credits available under federal law, Detroit Edison determined it would be prudent to initiate the application process for a new nuclear unit. Detroit Edison has not made a decision to build a new nuclear unit; however, it has elected to preserve its option to build at some point in the future by beginning the complex nuclear licensing process in 2007. Additionally, beginning the licensing process at the present time positions Detroit Edison to potentially take advantage of tax incentives derived from provisions in the 2005 Federal Energy Policy Act, which will benefit customers. To qualify for these tax credits, a combined operating license application for construction and operation of an advanced nuclear generating plant must be filed with the Nuclear Regulatory Commission (NRC) no later than December 31, 2008. Detroit Edison filed the combined operating license application with the NRC on September 18, 2008. Formal NRC review and approval is expected to take 3- 4 years and is estimated to cost an additional $57 million. Costs of $20 million related to preparing the combined licensing application have been deferred and included in Other assets as of September 30, 2008.

On August 31, 2007, Detroit Edison filed a supplement to its April 2007 rate case filing. A July 2007 decision by the State of Michigan Court of Appeals remanded back to the MPSC the November 2004 order in a prior Detroit Edison

rate case that denied recovery of merger control premium costs. The supplemental filing addressed recovery of approximately $61 million related to the merger control premium. The filing also included the impact of the July 2007 enactment of the MBT and other adjustments. The net impact of the supplemental filing resulted in an approximately $76 million average increase in Detroit Edison’s annual revenue requirement for 2008.

On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflected the use of 2009 as the projected test year and included a revised 2009 load forecast; 2009 revised estimates on environmental and advanced metering infrastructure capital expenditures; and adjustments to the calculation of the MBT. The update also included the August 2007 supplemental filing adjustments for the merger control premium, the new MBT and environmental operating and maintenance adjustments. The net impact of the updated filing resulted in an approximately $85 million average increase in Detroit Edison’s annual revenue requirement for 2009. The total filing requested a $284 million increase in Detroit Edison’s annual revenue for 2009. An MPSC order related to this filing is expected by early 2009.

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, Detroit Edison and MichCon filed applications with the MPSC to allow deferral of costs associated with the implementation of the Performance Excellence Process, a Company-wide cost-savings and performance improvement program. Detroit Edison and MichCon sought MPSC authorization to defer and amortize Performance Excellence Process implementation costs for accounting purposes to match the expected savings from the Performance Excellence Process program with the related CTA.

The Performance Excellence Process continued as of September 30, 2008. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA, subject to the MPSC establishing a recovery mechanism. Further, the order provided for Detroit Edison and MichCon to amortize the CTA deferrals over a 10-year period beginning with the year subsequent to the year the CTA was deferred. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon plans to seek a recovery mechanism in its next rate case which is expected to be filed in 2009. See Note 5 for additional information on amounts deferred and amortized in 2006 and 2007 and for the three and nine months ended September 30, 2008 and 2007.

Accounting for Costs Related to Enterprise Business Systems (EBS)

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At September 30, 2008, approximately $26 million of EBS costs have been deferred as a regulatory asset. EBS costs recorded as plant assets are being amortized over a 15-year period, pursuant to MPSC authorization.

Fermi 2 Enhanced Security Costs Settlement

The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In December 2006, Detroit Edison filed an application with the MPSC for recovery of $11.4 million of Fermi 2 Enhanced Security Costs (ESC), discounted back to September 11, 2001 plus carrying costs from that date. In April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi 2 ESC incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million plus carrying charges. A total of $13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization expense related to this regulatory asset was approximately $1 million and $3 million for the three- and nine-month periods ended September 30, 2008, respectively. Amortization of this regulatory asset was approximately $1 million and $2 million for the three- and nine-months ended September 30, 2007.

Reconciliation of Regulatory Asset Recovery Surcharge (RARS)

In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing RARS. This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS 5-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the 5-year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write-down of
RARS-related costs in 2007. As discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Detroit Edison had no CIM reductions for the three months ended September 30, 2008 due to the expiration of the CIM in April 2008. Approximately $20 million was credited to the unrecovered regulatory asset balance during the three months ended September 30, 2007. Approximately $11 million and $27 million was credited to the unrecovered regulatory asset balance during the nine months ended September 30, 2008 and 2007, respectively.

Power Supply Costs Recovery Proceedings

2005 Plan Year — In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval for recovery of an under-recovery of approximately $144 million at December 31, 2005 from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR plan year reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based on their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to its 2005 PSCR Reconciliation. An order was issued on May 22, 2007 approving a 2005 PSCR
under-collection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007. The 2005 under-collection surcharge was terminated in May 2008. The surcharge will be reconciled in the Company’s 2008 PSCR reconciliation.

2006 Plan Year — In March 2007, Detroit Edison filed its 2006 PSCR reconciliation that sought approval for recovery of an under-collection of approximately $51 million. Included in the 2006 PSCR reconciliation filing was the Company’s PEM reconciliation that reflects a $21 million over-collection which is subject to refund to customers. An MPSC order was issued on April 22, 2008 approving the 2006 PSCR under-collection amount of $51 million and the recovery of this amount as part of the 2007 PSCR factor. In addition, the order approved Detroit Edison’s PEM reconciliation and authorized the Company to refund the $22 million over-recovery, including interest, to customers in May 2008. The 2006 PEM refund was included in May 2008 customer bills. The refund will be reconciled in the Company’s 2008 PEM reconciliation.

2007 Plan Year — In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company’s application included a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR plan included fuel and power supply costs, including NOx and SO₂ emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. The Company reduced the PSCR factor to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 plan year projections and increased the PSCR factor to 8.69 mills/kWh on December 1, 2007. In August 2007, the MPSC approved Detroit

Edison’s 2007 PSCR plan case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007. The Company filed its 2007 PSCR reconciliation case in March 2008. The filing requests recovery of a $44 million PSCR under-collection through its 2008 PSCR plan. Included in the 2007 PSCR reconciliation filing was the Company’s 2007 PEM reconciliation that reflects a $21 million over-collection, including interest and prior year refunds. The Company expects an order in this proceeding in the second quarter of 2009.

2008 Plan Year — In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Company is supporting a total 2008 power supply expense forecast of $1.3 billion that includes $1 million for the recovery of its projected 2007 PSCR under-collection. Also included in the filing was a request for approval of the Company’s emission compliance strategy which included pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind) energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. In March 2008, the MPSC ordered that Detroit Edison shall not self-implement the 11.22 mills/kWh power supply cost recovery factor proposed in its January 2008 filing. Detroit Edison filed a renewed motion for a temporary order to implement the 11.22 mills/kWh factor in June 2008. On July 29, 2008, the MPSC issued a temporary order approving Detroit Edison’s request to increase the PSCR factor to 11.22 mills/kWh. The Company expects a final MPSC order in this proceeding in the fourth quarter of 2008.

2009 Plan Year — In September 2008, Detroit Edison filed its 2009 PSCR plan case seeking approval of a levelized PSCR factor of 17.67 mills/kWh above the amount included in base rates for residential customers and a levelized PSCR factor of 17.29 mills/kWh above the amount included in base rates for commercial and industrial customers. The Company is supporting a total power supply expense forecast of $1.73 billion. The plan also includes approximately $69 million for the recovery of its projected 2008 PSCR undercollection from all customers and approximately $12 million for the refund of its 2005 PSCR Reconciliation surcharge overcollection to commercial and industrial customers only. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a renewable (wind) energy project. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including; fuel costs, purchased and net interchange power costs, NOx and SO2 emission allowance costs, transmission costs and MISO costs.

Uncollectible Expense True-Up Mechanism (UETM) and Report of Safety and Training-Related Expenditures

2005 UETM — In March 2006, MichCon filed an application with the MPSC for approval of its UETM for 2005. This was the first filing MichCon made under the UETM, which was approved by the MPSC in April 2005 as part of MichCon’s last general rate case. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses totaled $60 million. The true-up mechanism allowed MichCon to recover 90% of uncollectibles that exceeded the $37 million base. Under the formula prescribed by the MPSC, MichCon recorded an under-recovery of approximately $11 million for uncollectible expenses from May 2005 (when the mechanism took effect) through the end of 2005. In December 2006, the MPSC issued an order authorizing MichCon to implement the UETM monthly surcharge for service rendered on and after January 1, 2007.

As part of the March 2006 application with the MPSC, MichCon filed a review of its 2005 annual safety and training-related expenditures. MichCon reported that actual safety and training-related expenditures for the initial period exceeded the pro-rata amounts included in base rates and, based on the under-recovered position, recommended no refund at that time. In the December 2006 order, the MPSC also approved MichCon’s 2005 safety and training report. On October 14, 2008, the State of Michigan Court of Appeals rejected the appeal of the Attorney General of the State of Michigan upholding the right of the MPSC to authorize MichCon to charge the 2005 UETM.

2006 UETM — In March 2007, MichCon filed an application with the MPSC for approval of its UETM for 2006 requesting $33 million of under-recovery plus applicable carrying costs of $3 million. The March 2007 application included a report of MichCon’s 2006 annual safety and training-related expenditures, which showed a $2 million

over-recovery. In August 2007, MichCon filed revised exhibits reflecting an agreement with the MPSC Staff to net the $2 million over-recovery and associated interest related to the 2006 safety and training-related expenditures against the 2006 UETM under-recovery. An MPSC order was issued in December 2007 approving the collection of $33 million requested in the August 2007 revised filing. MichCon was authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2008.

2007 UETM — In March 2008, MichCon filed an application with the MPSC for approval of its UETM for 2007 requesting approximately $34 million. This total includes $33 million of costs related to 2007 uncollectible expense and associated carrying charges and $1 million of under-collections for the 2005 UETM. The March 2008 application included a report of MichCon’s 2007 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. MichCon anticipates the MPSC will issue an order authorizing MichCon to implement the monthly UETM surcharge proposed in this filing for service rendered on and after January 1, 2009.

Gas Cost Recovery Proceedings

2005-2006 Plan Year — In June 2006, MichCon filed its GCR reconciliation for the 2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. MPSC Staff and other interveners filed testimony regarding the reconciliation in which they recommended disallowances related to MichCon’s implementation of its dollar cost averaging fixed price program. In January 2007, MichCon filed testimony rebutting these recommendations. In December 2007, the MPSC issued an order adopting the adjustments proposed by the MPSC Staff, resulting in an $8 million disallowance. Expense related to the disallowance was recorded in 2007. The MPSC authorized MichCon to roll a net over-recovery, inclusive of interest, of $20 million into its 2006-2007 GCR reconciliation. In December 2007, MichCon filed an appeal of the case with the Michigan Court of Appeals. MichCon is currently unable to predict the outcome of the appeal.

2006-2007 Plan Year — In June 2007, MichCon filed its GCR reconciliation for the 2006-2007 GCR year. The filing supported a total under-recovery, including interest through March 2007, of $18 million. In March 2008, the parties reached a settlement agreement that allowed for full recovery of MichCon’s GCR costs during the 2006-2007 GCR year. The settlement reflected the $20 million net over-recovery required by the MPSC’s order in its 2005-2006 GCR reconciliation. The under-recovery including interest through March 2007 agreed to under the settlement is $9 million and will be included in the 2007-2008 GCR reconciliation. An MPSC order was issued on April 22, 2008 approving the settlement.

2007-2008 Plan Year / Base Gas Sale Consolidated — 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 reached by all intervening parties that provided for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provided for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. The settlement agreement was approved by the MPSC in August 2007. 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 $54 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell through 2009. During 2007, MichCon sold 0.75 Bcf of base gas and recognized a pre-tax gain of $5 million. There were no sales of base gas in the first nine months of 2008. In June 2008, MichCon filed its GCR reconciliation for the 2007-2008 GCR year. The filing supported a total under-recovery, including interest through March 2008, of $10 million.

2008-2009 Plan Year — In December 2007, MichCon filed its GCR plan case for the 2008-2009 GCR Plan year. MichCon filed for a maximum GCR factor of $8.36 per Mcf, adjustable by a contingent mechanism. In June 2008, MichCon made an informational filing documenting the increase in market prices for gas since its December 2007 filing and calculating its new maximum factor of $10.76 per Mcf based on its contingent mechanism. On August 26, 2008, the MPSC approved a partial settlement agreement which includes the establishment of a new maximum base GCR factor of $11.36 per Mcf that will not be subject to adjustment by contingent GCR factors for the remainder of the 2008-2009 GCR plan year. An MPSC order in this case is expected in 2008.

2009 Proposed Native Base Gas Sale — 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.

Other

In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. In September 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger control premium as well as the recovery of transmission costs through the PSCR. The Company is unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.

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

NOTE 7 — COMMON STOCK AND EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options. Non-vested restricted stock awards are included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded. A reconciliation of both calculations is presented in the following table as of September 30:


	Three Months				Nine Months
	Ended September 30				Ended September 30
(in Millions, except per share amounts)	2008		2007		2008		2007
Basic Earnings per Share
Income from continuing operations	$	169	$	152	$	397	$	596

Average number of common shares outstanding		162		165		162		172

Income per share of common stock based on weighted average number of shares outstanding	$	1.04	$	0.93	$	2.45	$	3.47


Diluted Earnings per Share
Income from continuing operations	$	169	$	152	$	397	$	596

Average number of common shares outstanding		162		165		162		172
Incremental shares from stock-based awards		1		1		1		1

Average number of dilutive shares outstanding		163		166		163		173

Income per share of common stock assuming issuance of incremental shares	$	1.03	$	0.92	$	2.44	$	3.46

Options to purchase approximately 2 million shares of common stock as of September 30, 2008 were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 8 — LONG-TERM DEBT

Detroit Edison converted $238 million of tax-exempt bonds from an auction rate mode to a weekly rate mode in March 2008 due to a loss of liquidity in the auction rate markets. Detroit Edison then repurchased these bonds and held them until such time as it could either redeem and reissue the bonds or remarket the bonds in a longer-term mode. Approximately $187 million of these bonds have been redeemed and reissued and $51 million have been remarketed in a fixed rate mode to maturity.

Debt Issuances

In 2008, the Company has issued or remarketed the following long-term debt:

(in Millions)


Company	Month Issued	Type	Interest Rate	Maturity	Amount

MichCon	April	Senior Notes (1)	5.26%	2013	$	60
MichCon	April	Senior Notes (1)	6.04%	2018		100
MichCon	April	Senior Notes (1)	6.44%	2023		25
Detroit Edison	April	Tax-Exempt Revenue Bonds (2) (3)	Variable	2036		69
Detroit Edison	May	Tax-Exempt Revenue Bonds (2) (3)	Variable	2029		118
Detroit Edison	May	Tax-Exempt Revenue Bonds (2) (4)	5.30%	2030		51
MichCon	June	Senior Notes (5)	6.78%	2028		75
Detroit Edison	June	Senior Notes (1)	5.60%	2018		300
Detroit Edison	July	Tax-Exempt Revenue Bonds (2) (6)	Variable	2020		32
MichCon	August	Senior Notes (7)	5.94%	2015		140
MichCon	August	Senior Notes (7)	6.36%	2020		50
Detroit Edison	October	Senior Notes (1)	6.40%	2013		250

					$	1,270


(1)		Proceeds were used to pay down short-term debt and for general corporate purposes.

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

(3)		Proceeds were used to refinance auction rate Tax-Exempt Revenue Bonds.

(4)		These Tax-Exempt Revenue Bonds were converted from an auction rate mode and remarketed in a fixed rate mode to maturity.

(5)		Proceeds were used to repay the 6.45% Remarketable Securities due 2038 subject to mandatory or optional tender on June 30, 2008.

(6)		Proceeds were used to refinance Tax-Exempt Revenue Bonds that matured July 2008.

(7)		Proceeds were used to repay a portion of the $200 million MichCon 6.125% Senior Notes due September 2008.

Debt Retirements and Redemptions

In 2008, the following debt has been retired, through optional redemption or payment at maturity:

(in Millions)

Company

Month Retired

Type

Interest Rate

Maturity

Amount

Detroit Edison

April

Tax-Exempt Revenue Bonds (1)

Variable

2036

Detroit Edison

May

Tax-Exempt Revenue Bonds (1)

Variable

2029

118

MichCon

June

Remarketable Securities (2)

6.45%

2038

Detroit Edison

July

Tax-Exempt Revenue Bonds (3)

7.00%

2008

MichCon

September

Senior Notes (4)

6.125%

2008

200

494


(1)		These Tax-Exempt Revenue Bonds were converted from auction rate mode and subsequently redeemed with proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.

(2)		These Remarketable Securities were optionally redeemed by MichCon with proceeds from the issuance of new MichCon Senior Notes.

(3)		These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.

(4)		These Senior Notes were redeemed with the proceeds from the issuance of new MichCon Senior Notes and short-term debt.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, the EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.1 billion through 2007. The Company estimates Detroit Edison future capital expenditures at up to $282 million in 2008 and up to $2.4 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

Water — In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the 4 to 6 years subsequent to 2007 in additional capital expenditures to comply with these requirements. However, a recent court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies.

Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. Liabilities accrued for remediation of these sites were approximately $12 million at September 30, 2008 and $15 million at December 31, 2007. The costs to remediate are expected to be incurred over the next several years.

Gas Utility

Contaminated Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Gas Utility owns, or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing

at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. At September 30, 2008 and December 31, 2007, Gas Utility had liabilities of approximately $38 million and $40 million, respectively, for estimated investigation and remediation costs at former MGP sites and related regulatory assets.

Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. However, the Company anticipates the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on its results of operations.

Non-Utility

The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. The Company is in the process of installing new environmental equipment at its coke battery facility in Michigan. The Company expects the project to be completed during 2009. The coke battery facility received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. Below are the details of specific material guarantees the Company currently provides.

Millennium Pipeline Project Guarantee

The Company owns a 26.25% equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium is expected to begin commercial operations in December 2008.

On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010. The amount outstanding under this facility was $772 million at September 30, 2008. Proceeds of the facility are being used to fund project costs and expenses relating to the development, construction and commercial start up and testing of the pipeline project and for general corporate purposes. In addition, the facility has been utilized to reimburse the project partners for costs and expenses incurred in connection with the project for the period subsequent to June 1, 2004 through immediately prior to the closing of the facility.

The Company has agreed to guarantee 26.25% of the borrowing facility in the event of default by Millennium. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. The Company has also provided performance guarantees in regards to completion of Millennium to the major shippers in an amount of approximately $16 million. Millennium has contractual obligations to begin commercial operations on January 1, 2009. The maximum potential amount of future payments under these guarantees is approximately $226 million. There are no recourse provisions or collateral that would enable us to recover any amounts paid under the guarantees other than our share of project assets.

Parent Company Guarantee of Subsidiary Obligations

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post.

The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas and power) and the provisions and maturities of the underlying transactions. As of September 30, 2008, the value of the transactions for which the Company is exposed to collateral requests is approximately $500 million. The Company believes that the actual amount ultimately posted would be much less than this aggregate exposure.

Other Guarantees

The Company’s other guarantees are not individually material, with maximum potential payments of $10 million as of September 30, 2008.

Labor Contracts

There are several bargaining units for the Company’s represented employees. In September 2008, approximately 500 employees in the Company’s electric operations ratified a new four-year contract. The contracts of the remaining represented employees expire at various dates in 2009 and 2010.

Purchase Commitments

Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments totals $5 million as of September 30, 2008 and is being amortized to Fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. The Company estimates steam and electric purchase commitments from 2008 through 2024 will not exceed $343 million. In 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA through December 2008. Also, the Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may use for capital improvements to the steam heating system and during 2007 recorded a liability of $13 million related to the bank loan guarantee.

As of September 30, 2008, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.9 billion from 2008 through 2051. The Company also estimates that 2008 capital expenditures will be approximately $1.5 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company transacts with numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of the Company’s customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts, and records provisions for amounts considered at risk of probable loss. Management believes the Company’s previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on the Company’s consolidated financial statements.

Other Contingencies

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

See Note 6 for a discussion of contingencies related to regulatory matters.

NOTE 10 — SEGMENT INFORMATION

Beginning in the second quarter of 2008, the Company realigned its 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. The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility

•

The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan.

Gas Utility

•

The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 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.

Non-Utility Operations

	•		Gas Midstream consists of gas pipelines and storage businesses;

	•		Unconventional Gas Production is engaged in unconventional gas project development and production;

	•		Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, biomass energy projects and coal transportation and marketing; and

	•		Energy Trading primarily consists of energy marketing and trading operations.

Corporate & Other primarily consists of corporate staff functions that are fully allocated to the various segments based on services utilized. Additionally, Corporate & Other holds certain non-utility debt and energy-related investments.

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated federal tax return.

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


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Electric Utility	$	5		$	20		$	11		$	29
Gas Utility		3			1			6			4
Gas Midstream		2			5			7			13
Unconventional Gas Production		—			—			—			63
Power and Industrial Projects		8			34			77			140
Energy Trading		24			26			96			43
Corporate & Other		(18	)		(18	)		(60	)		(16	)

	$	24		$	68		$	137		$	276

Financial data of the business segments follows:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2008			2007			2008			2007
Operating Revenues
Electric Utility	$	1,440		$	1,403		$	3,766		$	3,707
Gas Utility		225			173			1,537			1,358
Non-utility Operations:
Gas Midstream		19			16			53			49
Unconventional Gas Production (1)		14			15			37			(244	)
Power and Industrial Projects		264			298			778			972
Energy Trading		405			292			1,128			700

		702			621			1,996			1,477


Corporate & Other		(5	)		(1	)		(3	)		1
Reconciliation & Eliminations		(24	)		(68	)		(137	)		(276	)

Total From Continuing Operations	$	2,338		$	2,128		$	7,159		$	6,267


Net Income (Loss) by Segment:
Electric Utility	$	159		$	107		$	251		$	207
Gas Utility		(15	)		(29	)		33			31
Non-utility Operations:
Gas Midstream		11			9			27			25
Unconventional Gas Production (1)(2)		3			1			89			(208	)
Power and Industrial Projects		26			9			30			26
Energy Trading		19			45			36			33

Corporate & Other (3)		(34	)		10			(69	)		482

Income (Loss) from Continuing Operations
Utility		144			78			284			238
Non-utility		59			64			182			(124	)
Corporate & Other		(34	)		10			(69	)		482

		169			152			397			596


Discontinued Operations (4)		8			45			20			120

Net Income	$	177		$	197		$	417		$	716


(1)		2007 Operating Revenues and Net Loss include recognition of losses on hedge contracts associated with the Antrim sale transaction. See Note 4.

(2)		2008 Net Income of the Unconventional Gas Production segment in the nine month period results primarily from the after-tax gain on the sale of a portion of the Barnett shale properties. See Note 4.

(3)		2007 Net Income results principally from the gain recognized on the Antrim sale transaction. See Note 4.

(4)		Discontinued operations of synthetic fuel business as of December 31, 2007. See Note 4.

Part II — Other Information

Item 1. — Legal Proceedings

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

We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could potentially be significant. To date, the Company has not been properly served process in this matter. Nevertheless, as a result of a recent decision by a Canadian court, a trial schedule has been initiated. The Company believes the claims of the Waterkeeper Alliance in this matter are without legal merit and has appealed the court’s decision. We are not able to predict or assess the outcome of this action at this time.

The City of Detroit Water and Sewer Department (DWSD) has a suit pending in U.S. District Court for the Eastern District of Michigan against EES Coke Battery, LLC (EES Coke), which is an indirect wholly owned subsidiary of the Company, alleging that certain constituents of waste water discharged by EES Coke into DWSD’s sewer system exceeded the permitted amounts. DWSD has requested that EES Coke be required to obtain a new permit and to pay fines for past excess amounts. DWSD and EES Coke are negotiating a consent order to settle this matter that will require EES Coke to pay fines in excess of $100,000. EES Coke is making capital improvements that are intended to prevent exceeding the permitted amounts in the future.

Item 1A. — Risk Factors

There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. Our 2007 Form 10-K includes a detailed discussion of our risk factors. The information presented below amends and restates a certain risk factor and should be read in conjunction with the risk factors and information disclosed in our 2007 Form 10-K. Additional risks and uncertainties not currently known to the Company, or that are currently deemed to be immaterial, also may materially adversely affect the Company’s business, financial condition and/or future operating results.

Michigan’s electric Customer Choice program could negatively impact our financial performance. The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. MPSC rate orders and recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity and have placed a cap on the total potential Customer Choice related migration. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. Even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases.

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

The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Securities Exchange Act of 1934 during the three months ended September 30, 2008:


					Total Number of		Maximum Dollar
					Shares Purchased		Value that May Yet
	Total Number		Average		as Part of Publicly		Be Purchased Under
	of Shares		Price Paid		Announced Plans		the Plans or
Period	Purchased (1)		Per Share		or Programs		Programs (2)
07/01/08 - 07/31/08		1,200	$	43.07		—	$	822,895,623
08/01/08 - 08/31/08		20,000	$	42.25		—	$	822,895,623
09/01/08 - 09/30/08		—		—		—	$	822,895,623

Total		21,200	$	42.30		—


(1)		Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program.

(2)		In January 2005, the DTE Energy Board of Directors authorized the repurchase of up to $700 million in common stock through 2008. In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to an additional $850 million of common stock through 2009. Through September 30, 2008, repurchases of approximately $725 million of common stock were made under these authorizations. These authorizations provide Company management with flexibility to pursue share repurchases from time to time, and will depend on future asset monetization, cash flows and investment opportunities.

Item 6. — Exhibits


Exhibit
Number		Description

Exhibits filed herewith:

4-250		Forty-First Supplemental Indenture, dated as of August 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., Trustee establishing the 2008 Series H and I Collateral Bonds.

4-251		Eighth Supplemental Indenture, dated as of August 1, 2008 to Supplemental to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., Trustee, establishing the 5.94% Senior Notes, 2008 Series H due 2015 and 6.36% Senior Notes, 2008 Series I due 2020.

31-43		Chief Executive Officer Section 302 Form 10-Q Certification.

31-44		Chief Financial Officer Section 302 Form 10-Q Certification.

Exhibits incorporated herein by reference:

4-252		Supplemental Indenture, dated as of October 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A. as successor trustee, providing for General and Refunding Mortgage Bonds, 2008 Series J (Exhibit 4-259 to The Detroit Edison Company’s Form 10-Q for the quarter ended September 30, 2008).

4-253		Twenty-Seventh Supplemental Indenture, dated as of October 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A. providing for 2008 Series J 6.40% Senior Notes due 2013 (Exhibit 4-260 to The Detroit Edison Company’s Form 10-Q for the quarter ended September 30, 2008).

Exhibits furnished herewith:

32-43		Chief Executive Officer Section 906 Form 10-Q Certification.

32-44		Chief Financial Officer Section 906 Form 10-Q Certification.

SIGNATURE

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


	DTE ENERGY COMPANY (Registrant)
Date: November 4, 2008	/s/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer