DTE Electric 10-Q 2008 Q3 Quarterly report

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 1-2198

The Detroit Edison Company meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is, therefore, filing this Form with the reduced disclosure format.

THE DETROIT EDISON COMPANY

(Exact name of registrant as specified in its charter)

Michigan (State or other jurisdiction of incorporation or organization)	38-0478650 (I.R.S. Employer Identification No.)
2000 2nd Avenue, Detroit, Michigan (Address of principal executive offices)	48226-1279 (Zip Code)

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

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

Yesþ 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 filero	Accelerated filero	Non-accelerated filerþ	Smaller reporting companyo
		(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).

Yeso No þ

All of the registrant’s 138,632,324 outstanding shares of common stock are owned by DTE Energy Company.

The Detroit Edison Company
Quarterly Report on Form 10-Q
Quarter Ended September 30, 2008

Table Of Contents

	Page
Definitions		1
Forward-Looking Statements		2
Part I — Financial Information
Item 1. Financial Statements
Consolidated Statements of Financial Position (Unaudited)		10
Consolidated Statements of Operations (Unaudited)		12
Consolidated Statements of Cash Flows (Unaudited)		13
Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Unaudited)		14
Notes to Consolidated Financial Statements (Unaudited)		15
Item 2. Management’s Narrative Analysis of Results of Operations		3
Item 4. Controls and Procedures		9
Part II — Other Information
Item 1. Legal Proceedings		30
Item 1A. Risk Factors		30
Item 6. Exhibits		31
Signature		32
EXHIBIT 4.259
EXHIBIT 4.260
EX-12.31
EXHIBIT 31.43
EXHIBIT 31.44
EXHIBIT 32.43
EXHIBIT 32.44

Definitions

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.
Detroit Edison	The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
DTE Energy	DTE Energy Company, the parent of Detroit Edison and directly or indirectly the parent company of numerous non-utility subsidiaries
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MDEQ	Michigan Department of Environmental Quality
MISO	Midwest Independent System Operator, a Regional Transmission Organization
MPSC	Michigan Public Service Commission
NRC	Nuclear Regulatory Commission
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.
Units of Measurement
kWh	Kilowatthour of electricity
MW	Megawatt of electricity
MWh	Megawatthour of electricity

1

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 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 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 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, and purchased power;

• 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;

• 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 Detroit Edison.

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.

2

Part I — Item 2.

The Detroit Edison Company

Management’s Narrative Analysis of Results of Operations

The Management’s Narrative Analysis of Results of Operations discussion for Detroit Edison is presented in accordance with General Instruction H(2) (a) of Form 10-Q.

Factors Impacting Income

Net income increased by $52 million in the third quarter of 2008 and increased by $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
Depreciation and Amortization		193			203			563			583
Taxes Other Than Income		54			63			176			204
Other Asset (Gains), Losses and 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 margindecreased $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. The 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 5 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	)

3

	Three Months Ended						Nine Months Ended
Power Generated and Purchased	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 maintenanceexpense 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 amortizationexpense 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.

4

Taxes other than incomedecreased $9 million in the third quarter of 2008 and $28 million in the nine-month period ended September 30, 2008 due 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, netdecreased $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 below. 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.

5

Impact of Legislation

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.

6

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.

7

• 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 Financial Markets

As part of the normal course of business, Detroit Edison routinely enters into physical or financially settled contracts for the purchase and sale of electricity, coal and other energy-related goods and services. Certain of these contracts contain provisions which allow the counterparties to request that we post cash or letters of credit in the event that the credit rating of Detroit Edison 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, and inter-company borrowings from our parent, DTE Energy, 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 our 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.

8

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 the Company’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.

9

Part I — Item 1.

The Detroit Edison Company

Consolidated Statements of Financial Position (Unaudited)

	September 30			December 31
(in Millions)	2008			2007
ASSETS
Current Assets
Cash and cash equivalents	$	93		$	47
Restricted cash		34			135
Accounts receivable (less allowance for doubtful accounts of $119 and $93, respectively)
Customer		754			727
Affiliates		4			3
Other		109			90
Accrued power supply cost recovery revenue		78			75
Inventories
Fuel		175			150
Materials and supplies		171			165
Prepaid property taxes		86			45
Other		11			15
		1,515			1,452
Investments
Nuclear decommissioning trust funds		756			824
Other		101			111
		857			935
Property
Property, plant and equipment		14,764			14,372
Accumulated depreciation		(5,826	)		(5,640	)
		8,938			8,732
Other Assets
Regulatory assets		2,529			2,511
Securitized regulatory assets		1,035			1,124
Intangible assets		18			9
Other		83			122
		3,665			3,766
Total Assets	$	14,975		$	14,885

10

The Detroit Edison Company
Consolidated Statements of Financial Position (Unaudited)

	September 30		December 31
(in Millions, Except Shares)	2008		2007
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Accounts payable — affiliates	$	129	$	138
Accounts payable other		307		396
Accrued interest		73		77
Dividends payable		—		76
Accrued vacations		56		52
Short-term borrowings — affiliates		8		277
Short-term borrowings other		373		406
Current portion of long-term debt, including capital leases		153		174
Other		298		243
		1,397		1,839
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		3,792		3,473
Securitization bonds		933		1,065
Capital lease obligations		35		42
		4,760		4,580
Other Liabilities
Deferred income taxes		1,867		1,825
Regulatory liabilities		574		583
Asset retirement obligations		1,192		1,160
Unamortized investment tax credit		87		95
Nuclear decommissioning		122		134
Accrued pension liability — affiliates		389		374
Accrued postretirement liability — affiliates		827		816
Other		184		176
		5,242		5,163
Commitments and Contingencies (Notes 4 and 6)
Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, and 138,632,324 shares issued and outstanding		2,946		2,771
Retained earnings		627		528
Accumulated other comprehensive income		3		4
		3,576		3,303
Total Liabilities and Shareholder’s Equity	$	14,975	$	14,885

11

The Detroit Edison Company

Consolidated Statements of Operations (Unaudited)

	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
Operating Expenses
Fuel and purchased power		586			518			1,403			1,274
Operation and maintenance		292			386			1,019			1,114
Depreciation and amortization		193			203			563			583
Taxes other than income		54			63			176			204
Asset (gains) and reserves, net		(1	)		6			(1	)		12
		1,124			1,176			3,160			3,187
Operating Income		316			227			606			520
Other (Income) and Deductions
Interest expense		73			73			220			222
Interest income		(1	)		(2	)		(3	)		(5	)
Other income		(16	)		(8	)		(39	)		(26	)
Other expenses		11			7			34			22
		67			70			212			213
Income Before Income Taxes		249			157			394			307
Income Tax Provision		90			50			143			100
Net Income	$	159		$	107		$	251		$	207

12

The Detroit Edison Company

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30
(in Millions)	2008			2007
Operating Activities
Net Income	$	251		$	207
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		563			583
Deferred income taxes		70			(191	)
Asset (gains) and reserves, net		(1	)		12
Changes in assets and liabilities, exclusive of changes shown separately		(33	)		367
Net cash from operating activities		850			978
Investing Activities
Plant and equipment expenditures		(651	)		(598	)
Restricted cash for debt redemptions		101			45
Proceeds from sale of nuclear decommissioning trust fund assets		180			227
Investment in nuclear decommissioning trust funds		(202	)		(254	)
Notes receivable from affiliates		—			(139	)
Other investments		(33	)		(16	)
Net cash used for investing activities		(605	)		(735	)
Financing Activities
Issuance of long-term debt		566			—
Redemption of long-term debt		(166	)		(132	)
Repurchase of long-term debt		(238	)		—
Short-term borrowings other		(33	)		(37	)
Short-term borrowings — affiliates		(268	)		—
Capital contribution by parent company		175			175
Dividends on common stock		(228	)		(228	)
Other		(7	)		(5	)
Net cash used for financing activities		(199	)		(227	)
Net Increase in Cash and Cash Equivalents		46			16
Cash and Cash Equivalents at Beginning of the Period		47			27
Cash and Cash Equivalents at End of the Period	$	93		$	43

13

The Detroit Edison Company

Consolidated Statements of Changes in Shareholder’s Equity and Comprehensive Income

(Unaudited)

										Accumulated
					Additional					Other
	Common Stock				Paid In		Retained			Comprehensive
(Dollars in Millions, shares in thousands)	Shares		Amount		Capital		Earnings			Income			Total
Balance, December 31, 2007		138,632	$	1,386	$	1,385	$	528		$	4		$	3,303
Net income		—		—		—		251			—			251
Capital contribution by parent company		—		—		175		—			—			175
Dividends declared on common stock		—		—		—		(152	)		—			(152	)
Net change in unrealized losses on investments, net of tax		—		—		—		—			(1	)		(1	)
Balance, September 30, 2008		138,632	$	1,386	$	1,560	$	627		$	3		$	3,576

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

(in Millions)	2008			2007
Net income	$	251		$	207
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses) on investments:
Amounts reclassified to income, net of taxes of $- and $1		(1	)		2
Comprehensive income	$	250		$	209

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The Detroit Edison Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — GENERAL

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 classification.

Asset Retirement Obligations

The Company records asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligationsand 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. The Company has conditional retirement obligations for the disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, 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.

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	$	1,170
Accretion		58
Liabilities settled		(8	)
Revision in estimated cash flows		(10	)
Asset retirement obligations at September 30, 2008		1,210
Less amount included in current liabilities		(18	)
	$	1,192

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.

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Retirement Benefits and Trusteed Assets

Detroit Edison participates in various plans that provide pension and other postretirement benefits for DTE Energy and its affiliates. Detroit Edison is allocated net periodic benefit costs for its share of the amounts of the combined plans. In 2008, the sponsor of the pension plan was changed from Detroit Edison to DTE Energy Corporate Services, LLC. As a result, Detroit Edison’s accrued pension liability of $389 million at September 30, 2008 is reflected as an amount due to affiliate. The following details the components of net periodic benefit costs for qualified and non-qualified pension benefits and other postretirement benefits:

(in Millions)	Pension Benefits						Other Postretirement Benefits
Three Months Ended September 30	2008			2007			2008			2007
Service cost	$	11		$	13		$	12		$	13
Interest cost		38			36			23			21
Expected return on plan assets		(41	)		(36	)		(14	)		(13	)
Amortization of:
Net actuarial loss		6			12			7			13
Prior service cost		2			2			—			1
Net transition liability		—			—			1			2
Special termination benefits		—			3			—			—
Net periodic benefit cost	$	16		$	30		$	29		$	37

(in Millions)	Pension Benefits						Other Postretirement Benefits
Nine Months Ended September 30	2008			2007			2008			2007
Service cost	$	34		$	38		$	36		$	36
Interest cost		112			104			70			67
Expected return on plan assets		(123	)		(111	)		(43	)		(40	)
Amortization of:
Net actuarial loss		19			34			21			38
Prior service cost		5			5			1			3
Net transition liability		—			—			2			5
Special termination benefits		—			8			—			2
Net periodic benefit cost	$	47		$	78		$	87		$	111

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

The Company expects to contribute $150 million for 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 for 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 $76 million for postretirement medical and life insurance benefit 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.

Income Taxes

The Company’s effective income tax rate for the three months ended September 30, 2008 was 36% as compared to 32% for the three months ended September 30, 2007, and for the nine months ended September 30, 2008 was 36% as compared to 33% for the nine months ended September 30, 2007. The increase in effective tax rate was primarily attributable to higher state income taxes related to the Michigan Business Tax which was effective January 1, 2008. Unrecognized tax benefits at September 30, 2008 and at December 31, 2007, if recognized, would not materially impact our effective tax rate. We do not anticipate any significant changes in the unrecognized tax benefits during the next twelve months.

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Short-Term Credit Arrangements and Borrowings

Detroit Edison has a $206 million, five-year unsecured revolving credit facility expiring in October 2009 and a $69 million, five-year unsecured credit facility expiring in 2010. The five-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but are intended to provide liquidity support for our commercial paper program. Borrowings under the facilities are available at prevailing short-term interest rates. In addition, Detroit Edison has a separate $100 million short-term unsecured bank loan facility expiring in July 2009 with covenants identical to those specified under our back-up credit facilities. The agreements require us to maintain a debt to total capitalization ratio of no more than 0.65 to 1. Detroit Edison is currently in compliance with its covenants. At September 30, 2008, Detroit Edison had outstanding commercial paper and borrowings of $373 million. At October 31, 2008, amounts outstanding totaled $180 million.

Stock-Based Compensation

Our parent company, DTE Energy, follows SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. The Company received an allocation of costs associated with stock compensation and the related impact of cumulative accounting adjustments. The allocation for the three months ended September 30, 2008 and 2007 for stock-based compensation expense was approximately $3 million and $3 million, respectively, while such allocation was $13 million and $14 million for the nine months ended September 30, 2008 and 2007, respectively.

Consolidated Statements of Cash Flows

The following provides detail of the changes in assets and liabilities that are reported in the Consolidated Statements 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	$	(48	)	$	(103	)
Inventories		(31	)		(25	)
Pension liability — affiliates		59			36
Accounts payable		(46	)		329
Accrued PSCR refund		22			2
Income taxes payable		(10	)		173
General taxes		(11	)		32
Postretirement liability — affiliates		12			9
Other assets		(14	)		(303	)
Other liabilities		34			217
	$	(33	)	$	367
Supplementary Cash Information
Cash paid for interest (net of interest capitalized)	$	224		$	235
Cash paid for income taxes	$	2		$	112

Asset (gains) and reserves, net

The 2007 third quarter and nine-month period ended September 30, 2007 included $6 million and $12 million reserve adjustments , respectively, for a loan guaranty related to our former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).

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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. 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 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.

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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.

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 the adoption will not have a material impact on the Company’s 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.

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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 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:

								Net Balance at
(in Millions)	Level 1		Level 2			Level 3		September 30, 2008
Assets:
Nuclear decommissioning trusts	$	469	$	287		$	—	$	756
Employee benefit trust investments		—		56			—		56
Derivative assets		—		—			3		3
Total	$	469	$	343		$	3	$	815
Liabilities:
Deferred compensation	$	—	$	(1	)	$	—	$	(1	)
Derivative liabilities		—		(15	)		—		(15	)
Total	$	—	$	(16	)	$	—	$	(16	)
Net Assets at September 30, 2008	$	469	$	327		$	3	$	799

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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)	$	4
Changes in fair value recorded in income		2
Changes in fair value recorded in other comprehensive income		—
Purchases, issuances and settlements		(3	)
Transfers in/out of Level 3		—
Liability balance as of September 30, 2008	$	3
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	$	3

(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 $2 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 losses of $15 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.

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.

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Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including forwards, options and financial transmission rights. 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.

NOTE 4 — RESTRUCTURING

Restructuring — Performance Excellence Process

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. 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. See Note 5.

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(1)				Other Costs				Total Cost
(in Millions)	2008		2007		2008		2007		2008		2007
Costs incurred		—		3		9		16		9		19
Less amounts deferred or capitalized		—		3		9		16		9		19
Amount expensed	$	—	$	—	$	—	$	—	$	—	$	—

Nine Months Ended September 30	Employee Severance Costs(1)				Other Costs				Total Cost
(in Millions)	2008		2007		2008		2007		2008		2007
Costs incurred		—		14		21		30		21		44
Less amounts deferred or capitalized		—		14		21		30		21		44
Amount expensed	$	—	$	—	$	—	$	—	$	—	$	—

(1) Includes corporate allocations.

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NOTE 5 — REGULATORY MATTERS

Regulation

Detroit Edison is 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;

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• 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 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 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, commencing in 2006, to defer the incremental CTA, subject to the MPSC establishing a recovery mechanism. Further, the order provided for Detroit Edison to amortize the CTA deferrals over a 10-year period beginning with the year subsequent to the year the CTA was deferred. See Note 4 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

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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. In addition, 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. 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

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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.

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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. 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 6 — SHAREHOLDER’S EQUITY

In March 2008, DTE Energy made a capital contribution of $175 million to the Company.

NOTE 7 — 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 the following long-term debt:

(in Millions)
Month Issued	Type	Interest Rate			Maturity		Amount
April	Tax-Exempt Revenue Bonds (2) (3)	Variable				2036	$	69
May	Tax-Exempt Revenue Bonds (2) (3)	Variable				2029		118
May	Tax-Exempt Revenue Bonds (2) (4)		5.30	%		2030		51
June	Senior Notes (1)		5.60	%		2018		300
July	Tax-Exempt Revenue Bonds (2) (5)	Variable				2020		32
October	Senior Notes (1)		6.40	%		2013		250
							$	820

(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 refinance Tax-Exempt Revenue Bonds that matured July 2008.

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Debt Retirements and Redemptions

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

(in Millions)
Month Retired	Type	Interest Rate			Maturity		Amount
April	Tax-Exempt Revenue Bonds (1)	Variable				2036	$	69
May	Tax-Exempt Revenue Bonds (1)	Variable				2029		118
July	Tax-Exempt Revenue Bonds (2)		7.00	%		2008		32
							$	219

(1)	These Tax-Exempt Revenue Bonds were converted from auction rate mode, then repurchased and reissued in a weekly rate mode.
(2)	These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Environmental

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.

Labor Contracts

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

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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. The Company estimates that these commitments will be approximately $1.4 billion from 2008 through 2024. The Company also estimates that 2008 capital expenditures will be approximately $1 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 5 for a discussion of contingencies related to regulatory matters.

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Part II

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. Detroit Edison is not able to predict or assess the outcome of this action at this time.

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.

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Item 6. — Exhibits

Exhibit
Number	Description
Exhibits filed herewith:
4-259	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.
4-260	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.
12-31	Computation of Ratio of Earnings to Fixed Charges
31-43	Chief Executive Officer Section 302 Form 10-Q Certification
31-44	Chief Financial Officer Section 302 Form 10-Q Certification
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

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SIGNATURE

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

	THE DETROIT EDISON COMPANY (Registrant)
Date: November 14, 2008	/s/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer

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