DTE Electric 10-Q 2007 Q1 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 March 31, 2007

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 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

All of the registrant’s 138,632,324 outstanding shares of common stock, par value $10 per share, are owned by DTE Energy Company.

The Detroit Edison Company

Quarterly Report on Form 10-Q
Quarter Ended March 31, 2007

Table of Contents

	Page
Definitions		1
Forward-Looking Statements		2
Part I – Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations		8
Consolidated Statement of Financial Position		9
Consolidated Statement of Cash Flows		11
Consolidated Statement of Changes in Shareholder’s Equity and Comprehensive Income		12
Notes to Consolidated Financial Statements		13
Item 2. Management’s Narrative Analysis of Results of Operations		3
Item 4. Controls and Procedures		7
Part II – Other Information
Item 6. Exhibits		24
Signature		25
Chief Executive Officer Section 302 Form 10-Q Certification
Chief Financial Officer Section 302 Form 10-Q Certification
Chief Executive Officer Section 906 Form 10-Q Certification
Chief Financial Officer Section 906 Form 10-Q Certification

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
ITC	International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)
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 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, 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;

• implementation of the electric Customer Choice program;

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

• employee relations and the negotiation and impacts 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;

• binding arbitration, litigation and related appeals;

• 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; and

• implementation of new processes and new core information systems.

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 decreased $19 million in the first quarter of 2007 primarily due to increased depreciation and amortization expenses, higher operation and maintenance expenses, and an increase in reserves.

Increase (Decrease) in Statement of Operations	Three
Components Compared to Prior Year	Months
(in Millions)
Operating Revenues	$	44
Fuel and Purchased Power		45
Gross Margin		(1	)
Operation and Maintenance		4
Depreciation and Amortization		15
Taxes Other Than Income		3
Other Reserves		7
Operating Income		(30	)
Other (Income) and Deductions		(4	)
Income Tax Provision		(7	)
Net Income	$	(19	)

Gross margindeclined $1 million in the first quarter of 2007 due to lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding that provided for an annualized rate reduction of $53 million effective in September 2006 and an additional annualized rate reduction of $26 million effective in January 2007. Gross margins were also lower due to poor economic conditions, partially offset by higher margins due to returning sales from electric Customer Choice and the impacts of colder weather in the first quarter of 2007. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.

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

Increase (Decrease) in Gross Margin Components Compared	Three
to Prior Year	Months
(in Millions)
Weather related margin impacts	$	8
Return of customers from electric Customer Choice		17
Service territory economic performance		(14	)
Impact of MPSC rate orders		(18	)
Other, net		6
Decrease in gross margin	$	(1	)

3

	Three Months Ended
	March 31
Power Generated and Purchased	2007			2006
(in Thousands of MWh)
Power Plant Generation
Fossil		10,557			9,308
Nuclear		2,428			2,197
		12,985			11,505
Purchased Power		1,233			1,513
System Output		14,218			13,018
Less Line Loss and Internal Use		(784	)		(825	)
Net System Output		13,434			12,193
Average Unit Cost ($/MWh)
Generation (1)	$	15.41		$	14.66
Purchased Power	$	63.88		$	50.42
Overall Average Unit Cost	$	19.62		$	18.82

(1) Represents fuel costs associated with power plants.

	Three Months Ended
	March 31
	2007		2006
(in Thousands of MWh)
Electric Sales
Residential		3,786		3,836
Commercial		4,309		4,008
Industrial		3,374		3,154
Wholesale		735		675
Other		110		106
		12,314		11,779
Interconnections sales (1)		1,120		414
Total Electric Sales		13,434		12,193
Electric Deliveries
Retail and Wholesale		12,314		11,779
Electric Customer Choice		451		1,139
Electric Customer Choice – Self Generators (2)		67		224
Total Electric Sales and Deliveries		12,832		13,142

(1)	Represents power that is not distributed by Detroit Edison.
(2)	Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.

Operation and maintenance expenseincreased $4 million in the first quarter of 2007 due primarily to higher storm expense of $15 million, partially offset by lower generation expenses of $5 million and lower corporate support allocation charges of $6 million.

Depreciation and amortization expensewas higher by $15 million in the first quarter of 2007 due primarily to increased amortization of regulatory assets of $10 million consisting of $4 million for the amortization of regulatory assets, $3 million related to the electric Customer Choice Incentive mechanism and $3 million for the amortization of CTA, and higher depreciation of $1 million due to higher levels of depreciable plant.

4

Other reserveswere $7 million in the first quarter of 2007 representing a reserve for a loan guaranty related to the prior sale of Detroit Edison’s steam heating business to Thermal Ventures II, LP.

Outlook– We continue to improve the operating performance of Detroit Edison. We have resolved a portion of our regulatory issues and continue to pursue additional regulatory and/or legislative 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, 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. We intend to seek recovery of these costs 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 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. While we have not decided on construction of a new base-load nuclear facility, in February 2007, we announced that we will prepare a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the federal Energy Policy Act of 2005. We are also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.

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;

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

• potential new federal and state environmental requirements.

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 6 of the Notes to Consolidated Financial Statements.

In January 2007, the MPSC submitted the State of Michigan’s 21^st Century Energy Plan to the Governor of Michigan. The plan recommends that Michigan’s future energy needs be met through a combination of renewable resources and cleanest generating technology, with significant energy savings achieved by increased energy efficiency. The plan also recommends:

• a requirement that all retail electric suppliers obtain at least 10 percent of their energy supplies from renewable resources by 2015;

• an opportunity for utility-built generation, contingent upon the granting of a certificate of need and competitive bidding of engineering, procurement and construction services;

5

• investigating the cost of a requirement to bury certain power lines; and

• creation of a Michigan Energy Efficiency Program, administered by a third party under the direction of the MPSC with initial funding estimated at $68 million.

We continue to review the energy plan and are unable to predict the impact on the Company of the implementation of the plan.

ENTERPRISE BUSINESS SYSTEMS

In 2003, we began the development of our Enterprise Business Systems (EBS) project, an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management. As part of this initiative, we are implementing EBS software including, among others, products developed by SAP AG and MRO Software, Inc. The first phase of implementation occurred in 2005 in our fossil generation unit. The second phase of implementation began in April 2007. The conversion of data and the implementation and operation of EBS will be continuously monitored and reviewed and should ultimately strengthen our internal control structure and lead to increased cost efficiencies. Although our implementation plan includes detailed testing and contingency arrangements to ensure a smooth and successful transition, we can provide no assurance that complications will not arise that could interrupt our operations.

6

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 the Securities Exchange Act of 1934 (Exchange Act) Rules 13a-15(e) and 15d-15(e)) as of March 31, 2007, 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 March 31, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

In April 2007, we began implementing the second phase of our Enterprise Business Systems (EBS) project. EBS is an enterprise resource planning system initiative to improve existing processes and to implement new core information systems, relating to finance, human resources, supply chain and work management.

7

The Detroit Edison Company

Consolidated Statement of Operations (unaudited)

	Three Months Ended
	March 31
	2007			2006
(in Millions)
Operating Revenues	$	1,094		$	1,050
Operating Expenses
Fuel and purchased power		354			309
Operation and maintenance		348			345
Depreciation and amortization		182			167
Taxes other than income		72			69
Other reserves		7			—
		963			890
Operating Income		131			160
Other (Income) and Deductions
Interest expense		74			72
Interest income		(1	)		—
Other income		(11	)		(7	)
Other expenses		9			10
		71			75
Income Before Income Taxes		60			85
Income Tax Provision		20			27
Income Before Accounting Change		40			58
Cumulative Effect of Accounting Change		—			1
Net Income	$	40		$	59

See Notes to Consolidated Financial Statements (Unaudited)

8

The Detroit Edison Company

Consolidated Statement of Financial Position (Unaudited)

	March 31			December 31
	2007			2006
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	25		$	27
Restricted cash		85			132
Accounts receivable (less allowance for doubtful accounts of $72 )
Customer		568			601
Collateral held by others		41			—
Other		56			70
Accrued power supply cost recovery revenue		67			116
Inventories
Fuel		127			136
Materials and supplies		135			130
Other		93			54
		1,197			1,266
Investments
Nuclear decommissioning trust funds		760			740
Other		88			89
		848			829
Property
Property, plant and equipment		14,091			13,916
Less accumulated depreciation		(5,643	)		(5,580	)
		8,448			8,336
Other Assets
Regulatory assets		2,822			2,862
Securitized regulatory assets		1,208			1,235
Intangible assets		9			9
Other		72			74
		4,111			4,180
Total Assets	$	14,604		$	14,611

See Notes to Consolidated Financial Statements (Unaudited)

9

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

	March 31		December 31
	2007		2006
(in Millions, Except Shares)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	379	$	411
Accrued interest		40		79
Dividends payable		76		76
Accrued vacations		78		77
Short-term borrowings		242		277
Current portion of long-term debt, including capital leases		147		142
Other		308		288
		1,270		1,350
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		3,499		3,515
Securitization bonds		1,124		1,184
Capital lease obligations		48		50
		4,671		4,749
Other Liabilities
Deferred income taxes		1,895		1,928
Regulatory liabilities		267		255
Asset retirement obligations		1,084		1,069
Unamortized investment tax credit		102		105
Nuclear decommissioning		122		119
Accrued pension liability		369		364
Accrued postretirement liability		1,060		1,055
Other		508		502
		5,407		5,397
Commitments and 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		1,385		1,210
Retained earnings		480		516
Accumulated other comprehensive income		5		3
		3,256		3,115
Total Liabilities and Shareholder’s Equity	$	14,604	$	14,611

See Notes to Consolidated Financial Statements (Unaudited)

10

The Detroit Edison Company

Consolidated Statement of Cash Flows (Unaudited)

	Three Months Ended
	March 31
	2007			2006
(in Millions)
Operating Activities
Net Income	$	40		$	59
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		182			167
Deferred income taxes		(48	)		27
Other reserves		7			—
Changes in assets and liabilities, exclusive of changes shown separately		41			(113	)
Net cash from operating activities		222			140
Investing Activities
Plant and equipment expenditures		(253	)		(245	)
Proceeds from sale of assets, net		—			18
Restricted cash for debt redemptions		47			54
Proceeds from sale of nuclear decommissioning trust fund assets		57			37
Investment in nuclear decommissioning trust funds		(66	)		(47	)
Other investments		—			(8	)
Net cash used for investing activities		(215	)		(191	)
Financing Activities
Redemption of long-term debt		(73	)		(69	)
Short-term borrowings, net		(35	)		193
Capital contribution by parent company		175			—
Dividends on common stock		(76	)		(76	)
Other		—			(3	)
Net cash from (used for) financing activities		(9	)		45
Net Decrease in Cash and Cash Equivalents		(2	)		(6	)
Cash and Cash Equivalents at Beginning of the Period		27			26
Cash and Cash Equivalents at End of the Period	$	25		$	20

See Notes to Consolidated Financial Statements (Unaudited)

11

The Detroit Edison Company

Consolidated Statement of Changes in Shareholder’s Equity
and Comprehensive Income (unaudited)

										Accumulated
(Dollars in Millions,					Additional					Other
Shares in Thousands)	Common Stock				Paid In		Retained			Comprehensive
	Shares		Amount		Capital		Earnings			Income		Total
Balance, December 31, 2006		138,632	$	1,386	$	1,210	$	516		$	3	$	3,115
Net income		—		—		—		40			—		40
Capital contribution by parent company		—		—		175		—			—		175
Dividends declared on common stock		—		—		—		(76	)		—		(76	)
Net change in unrealized gains on investments, net of tax		—		—		—		—			2		2
Balance, March 31, 2007		138,632	$	1,386	$	1,385	$	480		$	5	$	3,256

The following table displays other comprehensive income for the three-month periods ended March 31:

	2007		2006
(in Millions)
Net income	$	40	$	59
Other comprehensive income, net of tax:
Net unrealized gains on investments:
Amounts reclassified from income, net of taxes of $1 and $-		2		—
Comprehensive income	$	42	$	59

See Notes to Consolidated Financial Statements (Unaudited)

12

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 2006 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 in our opinion include all adjustments necessary for a fair statement of the results for the interim periods presented. 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.

References in this report to “we,” “us,” “our,” or “Company” are to The Detroit Edison Company and its subsidiaries, collectively.

Asset Retirement Obligations

We have a legal retirement obligation for the decommissioning costs of our Fermi 1 and Fermi 2 nuclear plants. We have 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 disposal costs for PCB contained within transformers and circuit breakers. We recognize such obligations as liabilities at fair market value 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 we are currently recovering in rates. We defer such differences under SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.

A reconciliation of the asset retirement obligations for the first quarter of 2007 follows:

(in Millions)
Asset retirement obligations at January 1, 2007	$	1,069
Accretion		16
Liabilities settled		(1	)
Asset retirement obligations at March 31, 2007	$	1,084

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.

13

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 March 31	2007			2006			2007			2006
Service cost	$	13		$	13		$	11		$	12
Interest cost		34			34			23			22
Expected return on plan assets		(37	)		(34	)		(13	)		(12	)
Net loss		11			12			12			13
Prior service cost		2			2			1			1
Net transition liability		—			—			2			1
Special termination benefits		4			—			2			—
Net periodic benefit cost	$	27		$	27		$	38		$	37

During the three months ended March 31, 2007, we recorded pension costs of $4 million and other postretirement benefit costs of $2 million associated with our Performance Excellence Process, included in the table above.

During the first quarter of 2006, we made a cash contribution of $40 million to our postretirement benefit plans. We made no cash contributions to our postretirement benefit plans in the first quarter of 2007.

Income Taxes

We adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109 (FIN 48)on January 1, 2007. This interpretation prescribes a recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, we recognized a $0.7 million decrease in liabilities which was accounted for as an increase to the January 1, 2007 balance of retained earnings. The total amount of unrecognized tax benefits amounted to $11.9 million and $4.9 million at January 1, 2007 and March 31, 2007, respectively. The decline in unrecognized tax benefits during the three months ended March 31, 2007 was attributable to settlements with the Internal Revenue Service (IRS) for the 2002 and 2003 tax years. Unrecognized tax benefits totaling $0.1 million at January 1, 2007, if recognized, would impact our effective tax rate. None of the unrecognized tax benefits at March 31, 2007 would impact our effective tax rate if recognized.

We recognize interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on our Consolidated Statement of Operations. Accrued interest pertaining to income taxes totaled $0.9 million and $1.1 million at January 1, 2007 and March 31, 2007, respectively. We had no accrued penalties pertaining to income taxes. We recognized interest expense in relation to income taxes of $0.2 million for the three months ended March 31, 2007, while we had no such interest expense during the three months ended March 31, 2006.

Our U.S. federal income tax returns for years 2004 and beyond remain subject to examination by the IRS. We also file tax returns in certain state jurisdictions with varying statutes of limitation.

14

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 three months ended March 31, 2007 and 2006 for stock-based compensation expense was approximately $4 million in each period. The cumulative effect of the adoption of SFAS 123(R),Share Based Payments, effective January 1, 2006, was an increase in net income of $1 million for the three months ended March 31, 2006 as a result of estimating forfeitures for previously granted stock awards and performance shares.

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:

	Three Months Ended
	March 31
	2007			2006
(in Millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(9	)	$	(31	)
Inventories		7			5
Accrued pensions		13			26
Accounts payable		(2	)		20
Accrued power supply cost recovery refund		49			(22	)
Income taxes payable		62			(1	)
General taxes		11			8
Postretirement obligation		5			(21	)
Other assets		(35	)		(57	)
Other liabilities		(60	)		(40	)
	$	41		$	(113	)

Supplementary cash and non-cash information follows:

	Three Months Ended
	March 31
	2007		2006
(in Millions)
Cash Paid for:
Interest (excluding interest capitalized)	$	114	$	92
Income taxes	$	1	$	—

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Other reserves

Other reserves were $7 million in the first quarter of 2007 representing a reserve for a loan guaranty related to the prior sale of Detroit Edison’s steam heating business to Thermal Ventures II, LP.

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Accounting

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.

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 standard permits an entity to choose to measure many financial instruments and certain other items at fair-value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings 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 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. 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 credits.

The requirement to recognize the funded status of a defined benefit pension or defined benefit other postretirement plan and the related disclosure requirements was effective for fiscal years ending after December 15, 2006, and we adopted this portion of the standard on December 31, 2006. We requested and received agreement from the MPSC to record the additional liability amounts on the balance sheet as a regulatory asset.

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. The

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Statement provides two options for the transition to a fiscal year end measurement date. We have not yet determined which of the available transition measurement options we will use.

NOTE 3 – RESTRUCTURING

Performance Excellence Process

In mid-2005, we initiated a company-wide review of our operations called the Performance Excellence Process. 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 that began in 2005.

We have incurred costs to achieve (CTA) 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. We began amortizing deferred 2006 costs in 2007 as the recovery of these costs was provided for by the MPSC. Amortization expense amounted to $2.5 million for the three months ended March 31, 2007. We deferred approximately $13 million of CTA during the three months ended March 31, 2007. See Note 4.

Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statement of Operations. Deferred amounts are recorded in the Regulatory assets line on the Consolidated Statement of Financial Position. Expenses incurred for the three months ended March 31, 2007 and 2006 are as follows:

	Employee Severance Costs (1)				Other Costs				Total Cost
(in Millions)	2007		2006		2007		2006		2007		2006
Costs incurred:	$	8	$	—	$	7	$	12	$	15	$	12
Less amounts deferred or capitalized:		8		—		7		—		15		—
Amount expensed	$	—	$	—	$	—	$	12	$	—	$	12

(1) Includes corporate allocations.

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

NOTE 4 – REGULATORY MATTERS

Regulation

Detroit Edison is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and 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 retail electric rates should not be reduced in 2007. Detroit Edison filed its response explaining why its

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electric rates should not be reduced in 2007. 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. 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 balance. Approximately $3 million was credited to the unrecovered regulatory asset balance in the first quarter of 2007.

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 requests 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 in order to recover significant environmental compliance costs and inflationary increases, partially offset by net savings associated with the Performance Excellence Process. The filing is based on a return on equity of 11.25 percent on an expected 50 percent capital and 50 percent debt capital structure by year-end 2008.

In addition, Detroit Edison’s filing makes, 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 Electric Choice customers.

• Re-establish with modification the Choice Incentive Mechanism (“CIM”) originally established in the Detroit Edison 2006 show cause filing. The CIM tracks changes related to customers moving between Detroit Edison full service and Electric Choice.

• Terminate the Pension Equalization Mechanism.

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

• 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 conjunction with Michigan’s 21^stCentury Energy Plan, Detroit Edison has 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. The first new base load capacity would be required for Detroit Edison by 2017. 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 final decision to build a new nuclear unit. Detroit Edison is preserving its option to build at some point in the future by beginning the complex nuclear licensing process now. Also, beginning the licensing process today positions Detroit Edison potentially to take advantage of tax incentives of up to $320 million derived from the 2005 Energy Policy Act that will benefit customers. To qualify for these substantial tax

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credits, a combined operating license for construction and operation of an advanced nuclear generating plant must be docketed by the Nuclear Regulatory Commission no later than December 31, 2008. Preparation and approval of a combined operating license can take up to 4 years and is estimated to cost at least $60 million.

A final order related to this filing is expected in 2008.

Regulatory Accounting Treatment for Performance Excellence Process

In May 2006, Detroit Edison 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. 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. Detroit Edison anticipates that the Performance Excellence Process will be carried out over a two to three year period beginning in 2005. Detroit Edison’s CTA is estimated to total approximately $150 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. At year-end 2006, Detroit Edison recorded deferred CTA costs of $102 million as a regulatory asset and began amortizing deferred 2006 costs in 2007, as the recovery of these costs was provided for by the MPSC in its order approving the settlement of the show cause proceeding. During the three months ended March 31, 2007, Detroit Edison deferred CTA costs of $13 million. Amortization of prior year deferred CTA costs amounted to $2.5 million during the three months ended March 31, 2007.

Accounting for Costs Related to Enterprise Business Systems (EBS)

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs that would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At March 31, 2007, approximately $21 million of EBS costs have been deferred as a regulatory asset. In addition, EBS costs recorded as plant assets will be 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 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 $12 million, including carrying charges, has been recorded as a regulatory asset at March 31, 2007. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years.

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Reconciliation of Regulatory Asset Recovery Surcharge

In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing Regulatory Asset Recovery Surcharge (“RARS”). In this filing, Detroit Edison replaced estimated costs for 2003–2005 included in the last general rate case with actual costs incurred. Also reflected in the filing was the replacement of estimated revenues with actual revenues collected. This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS five-year recovery limit under PA 141. Detroit Edison’s filing indicated a $53 million deficiency for RARS-related costs from the level originally established. Detroit Edison seeks reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the five 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. Detroit Edison has subsequently adjusted its estimated deficiency to $49 million. An order is expected in 2007.

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. Included in the factor were power supply costs, transmission expenses and nitrogen oxide (NOx) emission allowance costs. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case. At December 31, 2005, Detroit Edison 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 sought 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 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. An order is expected in the first half of 2007.

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 mills 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 included a matrix which provided for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also included $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requested 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 its transmission assets to ITC Transmission in February 2003, the FERC froze ITC Transmission’s rates through December 2004. In approving the sale, FERC authorized ITC Transmission’s recovery of the difference between the revenue it would have collected and the actual revenue collected during the rate freeze period. This amount is estimated to be $66 million which is to be included in ITC Transmission’s rates over a five-year period beginning June 1, 2006. This increased Detroit

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Edison’s transmission expense in 2006 by approximately $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 allowed 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. 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. The Company filed its 2006 PSCR reconciliation case in March 2007. The $51 million undercollection amount reflected in that filing is being collected in the 2007 PSCR plan.

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 includes fuel and power supply costs, including NOx and sulfur dioxide 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.

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 – SHAREHOLDER’S EQUITY

In March 2007, DTE Energy made a capital contribution of $175 million to the Company.

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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 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 $875 million through 2006. We estimate Detroit Edison future capital expenditures at up to $222 million in 2007 and up to $2 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 the Company could incur up to approximately $53 million over the next three to five years in additional capital expenditures to comply with these requirements. However, a court decision remanded back to the EPA several provisions of the federal regulation resulting in a delay in complying with the regulation. The decision also raised the possibility that the Company 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 two former 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 $11 million which was accrued in 2006 and is expected to be incurred over the next several years. In addition, Detroit Edison expects to make approximately $5 million of capital improvements to the ash landfill in 2007.

Labor Contracts

There are several bargaining units for our represented employees. Approximately 3,239 of our represented employees are under contracts that expire in June 2007. The contract of the remaining represented employees expires in 2008.

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 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 totaling $31.5 million at March 31, 2007 is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. We purchased approximately $42 million of steam and electricity in 2006, 2005 and 2004. We estimate steam and electric purchase commitments from 2007 through 2024 will not exceed $386 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 $63 million for future commitments. Also, we have guaranteed bank loans of approximately $12.5 million that Thermal Ventures II, LP may use for capital improvements

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to the steam heating system. During the three months ended March 31, 2007, we recorded a $6.8 million reserve related to the bank loan guarantee.

As of March 31, 2007, 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. We estimate that these commitments will be approximately $1.3 billion from 2007 through 2020. We also estimate that 2007 capital expenditures will be $875 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 that we can estimate and are 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. An arbitration hearing in this matter ended in April 2007. A decision which is subject to an appeal process is expected in June 2007. While we believe we will prevail on the merits in this matter, a negative decision could have an adverse effect on our business.

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 we can estimate and 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.

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PART II — Other Information

Exhibits

Exhibit
Number	Description
Filed:
31-31	Chief Executive Officer Section 302 Form 10-Q Certification
31-32	Chief Financial Officer Section 302 Form 10-Q Certification
Furnished:
32-31	Chief Executive Officer Section 906 Form 10-Q Certification
32-32	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
Date: May 9, 2007	/s/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer

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Exhibit Index

Exhibit
Number	Description
31-31	Chief Executive Officer Section 302 Form 10-Q Certification
31-32	Chief Financial Officer Section 302 Form 10-Q Certification
32-31	Chief Executive Officer Section 906 Form 10-Q Certification
32-32	Chief Financial Officer Section 906 Form 10-Q Certification