DTE Electric 10-Q 2006 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, 2006

Commission file number 1-2198

The registrant 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.)
20002nd 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 Noo

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

Large accelerated filero      Accelerated filero      Non-accelerated filerþ

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

Yeso Noþ

The Detroit Edison Company

Quarterly Report on Form 10-Q
Quarter Ended September 30, 2006

Table of Contents

	Page
Definitions		1
Forward-Looking Statements		2
Part I — Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations		7
Consolidated Statement of Financial Position		8
Consolidated Statement of Cash Flows		10
Consolidated Statement of Changes in Shareholder’s Equity and Comprehensive Income		11
Notes to Consolidated Financial Statements		12
Item 2. Management’s Narrative Analysis of Results of Operations		3
Item 4. Controls and Procedures		6
Part II — Other Information
Item 1. Legal Proceedings		23
Item 6. Exhibits		23
Signature		24
Computation of Ratios of Earnings to Fixed Charges
Chief Executive Officer Section 302
Chief Financial Officer Section 302
Chief Executive Officer Section 906
Chief Financial Officer Section 906

Definitions

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) and any 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
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. The clause was suspended under Michigan’s restructuring legislation (signed into law June 5, 2000), which lowered and froze electric customer rates. The clause was reinstated by the MPSC effective January 1, 2004.
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 expect to be recoverable if customers switch to alternative energy suppliers.
Units of Measurement
gWh	Gigawatthour of electricity
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 contemplated, projected, estimated or budgeted. There are many factors that 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 and regulations, and the cost of remediation and compliance;

• nuclear regulations and operations associated with nuclear facilities;

• implementation of the electric Customer Choice program;

• impact of electric utility restructuring in Michigan, including legislative amendments;

• 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 that can be affected by credit agency ratings;

• the timing and extent of changes in interest rates;

• the level of borrowing;

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

• effects of competition;

• impact of regulation by 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;

• 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;

• uncollectible accounts receivable;

• 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 speak only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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 $24 million during the 2006 third quarter and $42 million in the 2006 nine-month period. These results primarily reflect higher gross margins, partially offset by increased depreciation and amortization expenses. The 2006 third quarter benefited from the deferral of costs to achieve (CTA) associated with our Performance Excellence Process.

Increase (Decrease) in Income Statement Components
Compared to Prior Year	Three			Nine
(in Millions)	Months			Months
Operating Revenues	$	51		$	251
Fuel and Purchased Power		(65	)		9
Gross Margin		116			242
Operation and Maintenance		(48	)		14
Depreciation and Amortization		137			162
Taxes Other Than Income		(4	)		(2	)
Asset (gains) and losses, net		25			25
Operating Income		6			43
Other (Income) and Deductions		(11	)		(1	)
Income Tax Provision		(7	)		2
Net Income	$	24		$	42

Gross marginsincreased $116 million during the 2006 third quarter and $242 million in the 2006 nine-month period. The quarterly and year-to-date improvements were primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather in 2006.

Increase (Decrease) in Gross Margin Components
Compared to Prior Year	Three			Nine
(in Millions)	Months			Months
Weather related margin impacts	$	(38	)	$	(71	)
Removal of residential rate caps effective January 1, 2006		106			160
Return of customers from electric Customer Choice		55			106
Service territory economic performance		(34	)		(13	)
Impact of MPSC 2004 PSCR order		39			39
Other, net		(12	)		21
Increase in gross margin performance	$	116		$	242

3

	Three Months Ended						Nine Months Ended
Power Generated and Purchased	September 30						September 30
(in Thousands of MWh)	2006			2005			2006			2005
Power Plant Generation
Fossil		10,867			11,578			29,382			30,887
Nuclear		1,873			1,979			4,991			6,304
		12,740			13,557			34,373			37,191
Purchased Power		3,085			2,347			7,917			5,156
System Output		15,825			15,904			42,290			42,347
Less Line Loss and Internal Use		(483	)		(888	)		(2,165	)		(2,237	)
Net System Output		15,342			15,016			40,125			40,110
Average Unit Cost ($/MWh)
Generation (1)	$	17.78		$	17.69		$	16.33		$	15.68
Purchased Power	$	68.28		$	123.36		$	58.89		$	92.39
Overall Average Unit Cost	$	27.62		$	33.29		$	24.30		$	25.02

(1) Represents fuel costs associated with power plants.

	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Thousands of MWh)	2006		2005		2006		2005
Electric Sales
Residential		4,883		5,554		12,233		13,371
Commercial		4,927		4,462		13,440		11,646
Industrial		3,695		3,197		10,058		9,118
Wholesale		719		599		2,096		1,719
Other		95		93		291		285
		14,319		13,905		38,118		36,139
Interconnections sales (1)		1,023		1,111		2,007		3,971
Total Electric Sales		15,342		15,016		40,125		40,110
Electric Deliveries
Retail and Wholesale		14,319		13,905		38,118		36,139
Electric Customer Choice		319		1,635		2,188		5,178
Electric Customer Choice – Self Generators (2)		215		62		693		429
Total Electric Sales and Deliveries		14,853		15,602		40,999		41,746

(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 $48 million in the third quarter of 2006 and increased $14 million in the 2006 nine-month period. Pursuant to MPSC authorization, in the third quarter of 2006, Detroit Edison deferred approximately $74 million of CTA, including all amounts incurred in the third quarter and approximately $49 million of costs that were previously expensed through June 30, 2006. In the third quarter of 2006, we had $16 million in lower storm expenses, which were offset by $13 million of increased distribution system maintenance and a $9 million increase in plant outages. The year-to-date increase of $14 million in operation and maintenance expense was primarily due to increased plant outages of $12 million, increased distribution system maintenance of $24 million, offset by $21 million in lower storm expenses.

4

Depreciation and amortizationexpense increased $137 million in the third quarter of 2006 and $162 million in the 2006 nine-month period due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $15 million increase in our asset retirement obligation at our Fermi 1 nuclear facility. We also had increased amortization of regulatory assets of $14 million related to electric Customer Choice and $7 million related to our securitized assets.

Asset (gains) and losses, netdecreased by $25 million as a result of our 2005 sale of land near our headquarters in Detroit, Michigan.

Outlook— We continue to improve the operating performance of Detroit Edison. During the past year, we have resolved a portion of our regulatory issues and continue to pursue additional regulatory solutions for structural problems within the Michigan market structure, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service.

Concurrently, we will move forward in our efforts to continue to improve performance. Looking forward, additional issues, such as rising prices for coal, uranium and health care 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 utilize the DTE Energy Operating System and the Performance Excellence Process 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. Should we be able to recover these costs in future rate cases, we may experience a growth in earnings. 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 the last 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build or expand a new base- load coal or nuclear facility, with an estimated cost of $1 billion to $2 billion for a new coal plant.

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

• 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 performance;

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

• economic conditions within the State of Michigan;

• weather, including the severity and frequency of storms; and

• levels of customer participation in the electric Customer Choice program.

We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are adequately addressed. We will accrue as regulatory assets any future unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We cannot predict the outcome of these matters. See Note 4.

5

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, 2006, 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 ensuring 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 ensure 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 met.

(b) Changes in internal control over financial reporting

There has been no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

6

The Detroit Edison Company

Consolidated Statement of Operations (unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2006			2005			2006			2005
Operating Revenues	$	1,460		$	1,409		$	3,685		$	3,434
Operating Expenses
Fuel and purchased power		539			604			1,257			1,248
Operation and maintenance		277			325			990			976
Depreciation and amortization		311			174			646			484
Taxes other than income		64			68			198			200
Asset (gains) and losses, net		(1	)		(26	)		(1	)		(26	)
		1,190			1,145			3,090			2,882
Operating Income		270			264			595			552
Other (Income) and Deductions
Interest expense		60			68			208			201
Interest income		(1	)		(1	)		(2	)		(2	)
Other income		(9	)		(6	)		(22	)		(19	)
Other expenses		9			9			29			34
		59			70			213			214
Income Before Income Taxes		211			194			382			338
Income Tax Provision		73			80			128			126
Net Income	$	138		$	114		$	254		$	212

See Notes to Consolidated Financial Statements (Unaudited)

7

The Detroit Edison Company

Consolidated Statement of Financial Position

v
	(Unaudited)
	September 30			December 31
(in Millions)	2006			2005
ASSETS
Current Assets
Cash and cash equivalents	$	18		$	26
Restricted cash		41			84
Accounts receivable
Customer (less allowance for doubtful accounts of $64 and $54, respectively)		608			528
Other		128			112
Accrued power supply cost recovery revenue		178			144
Inventories
Fuel		142			123
Materials and supplies		125			116
Other		102			43
		1,342			1,176
Investments
Nuclear decommissioning trust funds		709			646
Other		67			65
		776			711
Property
Property, plant and equipment		13,701			13,416
Less accumulated depreciation		(5,526	)		(5,595	)
		8,175			7,821
Other Assets
Regulatory assets		1,889			2,006
Securitized regulatory assets		1,264			1,340
Intangible assets		44			40
Other		73			75
		3,270			3,461
Total Assets	$	13,563		$	13,169

See Notes to Consolidated Financial Statements (Unaudited)

8

The Detroit Edison Company
Consolidated Statement of Financial Position

	(Unaudited)
	September 30			December 31
(in Millions, Except Shares)	2006			2005
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	389		$	392
Accrued interest		72			79
Dividends payable		76			76
Accrued vacations		79			80
Short-term borrowings		147			163
Accrued power supply cost recovery		1			129
Deferred income taxes		77			—
Current portion of long-term debt, including capital leases		141			135
Other		247			208
		1,229			1,262
Other Liabilities
Deferred income taxes		1,916			1,961
Regulatory liabilities		249			224
Asset retirement obligations (Note 1)		1,010			953
Unamortized investment tax credit		107			115
Nuclear decommissioning		94			85
Accrued pension liability		349			261
Other		800			787
		4,525			4,386
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		3,449			3,221
Securitization bonds		1,185			1,295
Capital lease obligations		52			57
		4,686			4,573
Contingencies (Notes 4 and 6)
Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, 138,632,324 shares issued and outstanding		1,386			1,386
Additional paid in capital		1,254			1,104
Common stock expense		(44	)		(44	)
Retained earnings		525			500
Accumulated other comprehensive income		2			2
		3,123			2,948
Total Liabilities and Shareholder’s Equity	$	13,563		$	13,169

See Notes to Consolidated Financial Statements (Unaudited)

9

The Detroit Edison Company

Consolidated Statement of Cash Flows (Unaudited)

	Nine Months Ended
	September 30
(in Millions)	2006			2005
Operating Activities
Net Income	$	254		$	212
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		646			484
Deferred income taxes		31			50
Gain on sale of assets, net		(1	)		(26	)
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(252	)		(46	)
Net cash from operating activities		678			674
Investing Activities
Plant and equipment expenditures		(735	)		(479	)
Proceeds from sale of other assets, net		22			30
Restricted cash for debt redemptions		43			46
Notes receivable from affiliate		—			85
Proceeds from sale of nuclear decommissioning trust funds		136			159
Investment in nuclear decommissioning trust funds		(163	)		(188	)
Other investments		(12	)		(46	)
Net cash used for investing activities		(709	)		(393	)
Financing Activities
Issuance of long-term debt		247			612
Redemption of long-term debt		(123	)		(795	)
Short-term borrowings, net		(16	)		141
Capital contribution by parent company		150			—
Dividends on common stock		(229	)		(229	)
Other		(6	)		(4	)
Net cash from (used for) financing activities		23			(275	)
Net Increase (Decrease) in Cash and Cash Equivalents		(8	)		6
Cash and Cash Equivalents at Beginning of the Period		26			6
Cash and Cash Equivalents at End of the Period	$	18		$	12

See Notes to Consolidated Financial Statements (Unaudited)

10

The Detroit Edison Company

Consolidated Statement of Changes in Shareholder’s Equity

and Comprehensive Income (unaudited)

													Accumulated
(Dollars in Millions,					Additional		Common						Other
Shares in Thousands)	Common Stock				Paid in		Stock			Retained			Comprehensive
	Shares		Amount		Capital		Expense			Earnings			Income		Total
Balance, December 31, 2005		138,632	$	1,386	$	1,104	$	(44	)	$	500		$	2	$	2,948
Net income		—		—		—		—			254			—		254
Capital contribution by parent company		—		—		150		—			—			—		150
Dividends declared on common stock		—		—		—		—			(229	)		—		(229	)
Balance, September 30, 2006		138,632	$	1,386	$	1,254	$	(44	)	$	525		$	2	$	3,123

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

(in Millions)	2006		2005
Net income	$	254	$	212
Comprehensive income	$	254	$	212

See Notes to Consolidated Financial Statements (Unaudited)

11

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 our 2005 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 the 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 in our opinion include all adjustments necessary for a fair statement of the results for the interim periods. 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.

We reclassified certain prior year balances to match the current year’s financial statement presentation.

Consolidated Statement of Cash Flows

A detailed analysis of the changes in assets and liabilities that are reported in the consolidated statement of cash flows follows:

	Nine Months Ended
	September 30
(in Millions)	2006			2005
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(116	)	$	(118	)
Inventories		(28	)		(12	)
Accrued pensions		104			82
Accounts payable		6			27
Accrued power supply cost recovery refund		(162	)		(121	)
Income taxes payable		76			70
General taxes		10			6
Postretirement obligation		21			42
Other assets		(136	)		(50	)
Other liabilities		(27	)		28
	$	(252	)	$	(46	)

Supplementary cash and non-cash information follows:

	Nine Months Ended
	September 30
(in Millions)	2006		2005
Cash Paid for:
Interest (excluding interest capitalized)	$	215	$	225
Income taxes	$	1	$	1
Non-cash Investing and Financing Activities
Sale of assets		—		13

12

Asset Retirement Obligations

We have recorded asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligationsand FASB Interpretation FIN No. 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. We identified conditional retirement obligations for disposal of asbestos at certain of our power plants. To a lesser extent, we have conditional retirement obligations at certain service centers, and PCB disposal costs within transformers and circuit breakers.

As to regulated operations, we believe that adoptions of SFAS No. 143 and FIN 47 result primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates. We will be deferring such differences under SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.

A reconciliation of the asset retirement obligation for the 2006 nine-month period follows:

(in Millions)
Asset retirement obligations at January 1, 2006	$	953
Accretion		47
Liabilities settled		(5	)
Revisions in estimated cash flows		15
Asset retirement obligations at September 30, 2006	$	1,010

A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

Retirement Benefits and Trusteed Assets

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

							Other Postretirement
(in Millions)	Pension Benefits						Benefits
Three Months Ended September 30	2006			2005			2006			2005
Service Cost	$	12		$	13		$	10		$	11
Interest Cost		34			33			22			19
Expected Return on Plan Assets		(34	)		(34	)		(12	)		(14	)
Amortization of
Net loss		11			13			14			11
Prior service cost		2			2			1			1
Net transition liability		—			—			2			2
Special Termination Benefits		14			—			2			—
Net Periodic Benefit Cost	$	39		$	27		$	39		$	30

13

							Other Postretirement
(in Millions)	Pension Benefits						Benefits
Nine Months Ended September 30	2006			2005			2006			2005
Service Cost	$	38		$	40		$	34		$	33
Interest Cost		102			99			66			59
Expected Return on Plan Assets		(102	)		(101	)		(37	)		(43	)
Amortization of
Net loss		34			38			40			33
Prior service cost		6			7			3			3
Net transition liability		—			—			5			5
Special Termination Benefits		28			—			3			—
Net Periodic Benefit Cost	$	106		$	83		$	114		$	90

During the third quarter of 2006, we recorded a $14 million pension cost and a $2 million postretirement benefit cost associated with our Performance Excellence Process. For the nine-month period ending September 30, 2006, we recorded a $28 million pension cost and a $3 million postretirement benefit cost associated with the Performance Excellence Process. In the third quarter we deferred $74 million of Performance Excellence Process costs pursuant to MPSC authorization. See Note 4. In 2006, we made cash contributions of $40 million to our postretirement benefit plans.

Affiliate Transactions

Detroit Edison shares costs with or incurs costs on behalf of unconsolidated affiliated companies. Prior to year end 2005, we recorded such costs within “Other expenses” and related reimbursement within “Other income” in the Consolidated Statement of Operations. These transactions do not affect combined other income and deductions or net income. Our financial statements now reflect such affiliate transactions exclusively within affiliate accounts receivable. Consistent with the current period’s presentation, previously reported amounts within the Consolidated Statement of Operations have been adjusted accordingly.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Stock-Based Compensation

Effective January 1, 2006, our parent company, DTE Energy, adopted SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. We receive an allocation of costs associated with stock compensation and the related impact of cumulative accounting adjustments.

Our allocation for the nine months of 2006 for stock-based compensation expense was approximately $10 million. The cumulative effect of the adoption of SFAS 123(R) was a decrease in operation and maintenance expense of $1 million in the first quarter of 2006. The cumulative effect adjustment was due to the estimation and subsequent allocation of forfeitures for previously granted stock awards and performance shares. We have not restated any prior periods as a result of the adoption of SFAS 123(R).

Accounting for Uncertainty in Income Taxes

In July 2006, the FASB issued Financial Interpretation No. 48 (FIN 48),Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 – Accounting for Income Taxes.FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109. Additionally, it prescribes a recognition threshold and

14

measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in the tax return. FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition and is effective for fiscal years beginning after December 15, 2006. We plan to adopt FIN 48 on January 1, 2007. We are currently assessing the effects of this interpretation, and have not yet determined the impact on the consolidated financial statements.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS 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 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We plan to adopt SFAS 157 on January 1, 2008. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R).SFAS 158 requires companies to (1) recognize the overfunded or underfunded status of defined benefit pension and defined benefit other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.

The requirement to recognize the funded status of a postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. We plan to adopt this requirement as of December 31, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We plan to adopt this requirement as of December 31, 2008. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

Accounting for Planned Major Maintenance

In September 2006, the FASB issued its Staff Position (FSP), AUG AIR-1,Accounting for Planned Major Maintenance Activities.This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. The FSP is effective for fiscal years beginning after December 15, 2006. We have historically charged expenditures for maintenance and repairs to expense as they were incurred, with the exception of Fermi 2, where we have utilized the accrue-in-advance policy for nuclear refueling outage costs since the plant was placed in service in 1988. We plan to adopt this FSP as of January 1, 2007. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

15

Quantifying Misstatements

In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N,Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements(SAB 108). SAB 108 addresses how a registrant should quantify the effect of an error on the financial statements. The SEC staff concludes in SAB 108 that a dual approach should be used to compute the amount of a misstatement. Specifically, the amount should be computed using both the “rollover” (current year income statement perspective) and “iron curtain” (year-end balance sheet perspective) methods. SAB 108 is effective for years ending after November 15, 2006. We plan to adopt SAB 108 as of December 31, 2006. We are currently assessing the effects of this statement, and have not yet determined the impact on the consolidated financial statements.

NOTE 3 — RESTRUCTURING

Restructuring — Performance Excellence Process

In mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. We have identified the Performance Excellence Process as critical to our long-term growth strategy. The overarching goal has been to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Additionally, we will need significant resources in the future to invest in maintaining the capital infrastructure and meeting compliance mandates. Specifically, we began a series of focused improvement initiatives within our Detroit Edison and associated corporate support functions. We expect this process will be carried out over a two- to three-year period beginning in 2006.

We have incurred costs to achieve (CTA) for employee severance and other costs, consisting primarily of project management and consultant support. Detroit Edison’s CTA is estimated to total between $160 million and $190 million. Pursuant to MPSC authorization, in the third quarter of 2006, Detroit Edison deferred approximately $74 million of CTA, including all amounts incurred in the third quarter and approximately $49 million of costs that were previously expensed through June 30, 2006. Detroit Edison will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. See Note 4.

Amounts expensed are recorded in within the operations and maintenance line in the consolidated statement of operations. Deferred amounts are recorded within the regulatory asset line in the consolidated statement of financial position. Expenses incurred in 2006 are as follows:

	Employee Severance Costs (1)					Other Costs (1)					Total Cost
	Three			Nine		Three			Nine		Three			Nine
	Months			Months		Months			Months		Months			Months
	Ended			Ended		Ended			Ended		Ended			Ended
(in Millions)	September			September		September			September		September			September
Business Segment	30			30		30			30		30			30
Costs incurred:
Electric Utility	$	18		$	36	$	10		$	41	$	28		$	77
Less amounts deferred or capitalized:
Electric Utility		36			36		41			41		77			77
Amount expensed or capitalized	$	(18	)	$	—	$	(31	)	$	—	$	(49	)	$	—

(1) Includes corporate allocations.

16

A liability for future CTA associated with the Performance Excellence Process has not been recognized because we have not met the recognition criteria pursuant to SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities.

NOTE 4 — REGULATORY MATTERS

Electric Rate Restructuring Proposal

In February 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies within the current pricing structure. In December 2005, the MPSC issued an that did not provide for the comprehensive realignment of the existing rate structure that Detroit Edison requested in its rate restructuring proposal. The MPSC order did take some initial steps to improve the current competitive imbalance in Michigan’s electric Customer Choice program. The December 2005 order established cost-based power supply rates for Detroit Edison’s full service customers. Electric Customer Choice participants will pay cost-based distribution rates, while Detroit Edison’s full service commercial and industrial customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers continue to pay a subsidized below-cost rate for distribution service. These revenue neutral revised rates were effective February 1, 2006. Detroit Edison was also ordered to file a general rate case by July 1, 2007, based on 2006 actual results.

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

In accordance with the MPSC’s directive in Detroit Edison’s November 2004 rate order, in March 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. In September 2006, the MPSC issued an order recognizing $19 million of 2004 net stranded costs that required Detroit Edison to write off $112 million of 2004 net stranded costs. The MPSC order resulted in a $39 million reduction in the 2004 PSCR over-collection by allowing Detroit Edison to retain the benefit of third party wholesale sales required to support the electric Customer Choice program and to offset the recognition of the $19 million of 2004 stranded costs. The MPSC order also resulted in adjustments to accrued interest on the 2004 and 2005 PSCR amounts of $15 million. The MPSC directed Detroit Edison to include the remaining 2004 PSCR over-collection amount and related interest in the 2005 PSCR Reconciliation which is in an under-collected position. The order resulted in a reduction of pre-tax income of approximately $58 million.

MPSC Show-Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its retail electric rates should not be reduced in 2007. The MPSC cited certain changes that have occurred since the November 2004 order in Detroit Edison’s last general rate case, or are expected to occur. These changes included: declines in electric Customer Choice program participation, expiration of the residential rate caps, and projected reductions in Detroit Edison operating costs. The show cause filing was to reflect sales, costs and financial conditions that were expected to occur by 2007. On June 1, 2006, Detroit Edison filed its response explaining why its electric rates should not be reduced in 2007. Detroit Edison indicated that it will have a revenue deficiency of approximately $45 million beginning in 2007 due to significant capital investments over the next several years for infrastructure improvements to enhance electric service reliability and for mandated environmental expenditures. The impacts of these investments will be partially offset by efficiency and cost-savings measures that have been initiated. Therefore, Detroit Edison requested that the show cause proceeding allow for rate increase adjustments based on the combined effects of investment expenditures and cost-savings programs. The MPSC denied this request and indicated that a full review of rates will be made in Detroit Edison’s next general rate case, which is due to be filed by July 1, 2007.

17

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 the later of March 31, 2008 or 12 months from the filing date of Detroit Edison’s next main case, rates will be reduced by an additional $26 million, for a total reduction of $79 million. 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 provides 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. The CIM has a deadband of ±200 GWh. 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 recovery balances.

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, we filed an application 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. Implementation costs include project management, consultant support and employee severance expenses. We 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. We anticipate that the Performance Excellence Process will be carried out over a two- to three-year period beginning in 2006. Our CTA is estimated to total between $160 million and $190 million. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. We recorded the deferred CTA costs of $74 million as a regulatory asset and will begin amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding.

Power Supply Costs Recovery Proceedings

2005 Plan Year— In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order. The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor are power supply costs, transmission expenses and nitrogen oxide (NOx) emission allowance costs. Detroit Edison self-implemented a factor of negative 2.00 mills per kWh on January 1, 2005. Effective June 1, 2005, Detroit Edison began billing the maximum allowable factor of 0.48 mills per kWh due to increased power supply costs. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case. At December 31, 2005, Detroit Edison has recorded an under-recovery of approximately $144 million related to the 2005 plan year. In March 2006, Detroit Edison filed its 2005 PSCR reconciliation. The filing seeks approval for recovery of approximately $144 million 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

18

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 upon their contributions to pension expense during the subject periods. The September 2006 order in the Company’s 2004 PSCR Reconciliation and Stranded Cost proceeding directed the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation, thereby reducing the Company’s 2005 PSCR Reconciliation under-collection amount for commercial and industrial customers to $64 million.

2006 Plan Year —In September 2005, Detroit Edison filed its 2006 PSCR plan case seeking approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 per kWh above the amount included in base rates for commercial and industrial customers. Included in the factor for all customers are fuel and power supply costs, including transmission expenses, Midwest Independent Transmission System Operator (MISO) market participation costs, and NOx emission allowance costs. The Company’s PSCR Plan includes a matrix which provides for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also includes $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requests MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and a fuel additive. In conjunction with DTE Energy’s sale of the transmission assets of ITC in February 2003, the FERC froze ITC’s transmission rates through December 2004. In approving the sale, FERC authorized ITC recovery of the difference between the revenue it would have collected and the actual revenue ITC did collect during the rate freeze period. At December 31, 2005, this amount is estimated to be $66 million which is to be included in ITC’s rates over a five-year period beginning June 1, 2006. It is expected that this amortization will increase Detroit Edison’s transmission expense in 2006 by $7 million. The MPSC authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.

In December 2005, the MPSC issued a temporary order authorizing the Company to begin implementation of maximum quarterly PSCR factors on January 1, 2006. The quarterly factors reflect a downward adjustment in the Company’s total power supply costs of approximately 2% to reflect the potential variability in cost projections. The quarterly factors will allow the Company to more closely track the costs of providing electric service to our customers and, because the non-summer factors are well below those ordered for the summer months, effectively delay the higher power supply costs to the summer months at which time our customers will not be experiencing large expenditures for home heating. The MPSC did not adopt the Company’s request to recover its projected 2005 PSCR under-collection associated with commercial and industrial customers nor did it adopt the Company’s request to implement contingency factors based upon the Company’s increased costs associated with providing electric service to returning electric Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company’s entire 2006 PSCR Plan. In September 2006, the MPSC issued an order in this case that approved the inclusion of sulfur dioxide emission allowance expense in the PSCR, determined that fuel additive expense should not be included in the PSCR based upon its impact on maintenance expense, found the Company’s determination of third party sales revenues to be correct, and allowed the Company to increase its PSCR factor for the balance of the year in an effort to reverse the effects of the previously ordered temporary reduction. This factor increase will effectively reduce the projected 2006 PSCR under-collection by $36 million to $130 million. The MPSC declined to rule on the Company’s requests to include mercury emission allowance expense in the PSCR or its request to include prior PSCR over/(under) recoveries in future year PSCR plans. We have filed a petition for re-hearing.

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 includes $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 includes a request for an early hearing and temporary order granting such ratemaking authority. The

19

Company’s 2007 PSCR Plan includes fuel and power supply costs, including NOx and sulfur dioxide emission allowance costs, transmission costs and MISO costs.

Electric Shut-Off and Restoration

In June 2006, the MPSC approved a settlement agreement with Detroit Edison regarding issues related to service restoration. The MPSC had determined that restoration of certain electric service shut-offs effected between October 28, 2005 and March 14, 2006 did not conform to MPSC rules. The settlement agreement directed Detroit Edison to bring its service restoration process into compliance with MPSC rules and submit monthly reports identifying progress toward compliance. Detroit Edison also paid a fine of $105,000 and filed a plan with the MPSC that details assistance customers can receive to avoid service shut-offs.

Revenue Sufficiency Guarantee

Since the April 2005 implementation of Midwest Independent Transmission System Operator (MISO) market operations, MISO’s business practice manuals and other instructions to market participants have stated that Revenue Sufficiency Guarantee (RSG) charges will not be imposed on day-ahead virtual offers to supply power. RSG charges are collected by MISO from market participants in order to compensate generators that are standing by to supply electricity when called upon by MISO. In an April 2006 order, FERC interpreted MISO’s tariff to require that virtual supply offers be subject to RSG charges. Thus, FERC ordered MISO to recalculate RSG charges, and assess the same on all virtual supply offers, retroactive to April 1, 2005. Numerous requests for rehearing were filed and in October 2006 FERC issued its order on rehearing as to refunds associated with virtual transactions. In this order, FERC reversed its earlier position and now finds retroactive refunds to be inappropriate.

Other

We are 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 5 — LONG -TERM DEBT

Debt Issuances

In 2006, we issued the following long-term debt:

					(in Millions)
	Month
Company	Issued	Type	Interest Rate	Maturity	Amount
Detroit Edison	May	Senior Notes (1)	6.625%	June 2036	$250

(1) The proceeds from the issuance were used to repay short-term borrowings of Detroit Edison and for general corporate purposes

NOTE 6 — 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, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will

20

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 $644 million through 2005. We estimate Detroit Edison’s future capital expenditures at up to $218 million in 2006 and up to $2.2 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.

Water— 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 intakes. It is estimated that we will incur up to $50 million over the next four to six years in additional capital expenditures for Detroit Edison.

Contaminated Sites— Detroit Edison conducted remedial investigations at contaminated sites, including two former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $13 million which was accrued in 2005 and is expected to be incurred over the next several years.

Personal Property Taxes

Detroit Edison and other Michigan utilities have asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions took legal action attempting to prevent the STC from implementing the new valuation tables and continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002, issued a decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. After a period of abeyance, the MTT issued a scheduling order in a significant number of Detroit Edison appeals that set litigation calendars for these cases extending into mid-2006. After an extended period of settlement discussions, a Memorandum of Understanding was reached with six principals in the litigation and the Michigan Department of Treasury that is expected to lead to settlement of all outstanding property tax disputes on a global basis.

On December 8, 2005, executed Stipulations for Consent Judgment, Consent Judgments, and Schedules to Consent Judgment were filed with the MTT on behalf of Detroit Edison and a significant number of the largest jurisdictions, in terms of tax dollars, involved in the litigation. The filing of these documents fulfilled the requirements of the global settlement agreement and resolves a number of claims by the litigants against each other including both property and non-property issues. The global settlement agreement resulted in a pre-tax economic benefit to Detroit Edison in 2005 that included the release of a litigation reserve.

Income Taxes

The Internal Revenue Service is currently conducting audits of our federal income tax returns for the years 2002 and 2003. We have accrued tax and interest related to tax uncertainties that arise due to actual or potential disagreements with governmental agencies about the tax treatment of specific items. At September 30, 2006, we have accrued approximately $6 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

21

Other 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 special charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. We purchased $42 million of steam and electricity in 2005 and 2004 and $39 million in 2003. We estimate steam and electric purchase commitments through 2024 will not exceed $427 million. In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

As of December 31, 2005, we were party to numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments and energy trading contracts. We estimate that these commitments will be approximately $1.3 billion through 2020. We also estimate that 2006 base level capital expenditures will be $800 million. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

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

Other

Detroit Edison is involved in a contract dispute with BNSF Railway Company that has been referred to arbitration. Under this contract, BNSF transports western coals east for Detroit Edison. We have filed a breach of contract claim against BNSF for the failure to provide certain services that we believe are required by the contract. The arbitration hearing is scheduled for mid-2007. While we believe we will prevail on the merits in this matter, a negative decision with respect to the significant issues being heard in the arbitration could have an adverse effect on our business.

Also, we are 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, 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.

See Note 4 for a discussion of contingencies related to regulatory matters.

22

Other Information

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. For additional discussion on legal matters, see the Notes to the Consolidated Financial Statements.

See Note 4 for a discussion of contingencies related to Regulatory Matters and Note 6 for a discussion of specific non-regulatory matters.

Exhibits

Exhibit
Number	Description
Filed:
12-26	Computation of Ratios of Earnings to Fixed Charges
31-27	Chief Executive Officer Section 302 Form 10-Q Certification
31-28	Chief Financial Officer Section 302 Form 10-Q Certification
Furnished:
32-27	Chief Executive Officer Section 906 Form 10-Q Certification
32-28	Chief Financial Officer Section 906 Form 10-Q Certification

23

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
Date: November 14, 2006	/s/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Controller

24

EXHIBIT INDEX

Exhibit
Number	Description
Filed:
12-26	Computation of Ratios of Earnings to Fixed Charges
31-27	Chief Executive Officer Section 302 Form 10-Q Certification
31-28	Chief Financial Officer Section 302 Form 10-Q Certification
Furnished:
32-27	Chief Executive Officer Section 906 Form 10-Q Certification
32-28	Chief Financial Officer Section 906 Form 10-Q Certification