exv99w3

Exhibit 99.3

DTE Energy Company
Consolidated Statement of Operations (Unaudited)


	Three Months Ended
	March 31
(in Millions, Except per Share Amounts)	2005			2004
Operating Revenues	$	2,315		$	2,093

Operating Expenses
Fuel, purchased power and gas		969			741
Operation and maintenance		904			783
Depreciation, depletion and amortization		208			167
Taxes other than income		91			85
Asset gains and losses, net		(76	)		(50	)

		2,096			1,726

Operating Income		219			367

Other (Income) and Deductions
Interest expense		128			131
Interest income		(14	)		(10	)
Other income		(12	)		(11	)
Other expenses		11			15

		113			125

Income Before Income Taxes and Minority Interest		106			242
Income Tax Provision		37			75
Minority Interest		(53	)		(30	)

Income from Continuing Operations		122			197
Income (Loss) from Discontinued Operations, net of tax (Note 3)		—			(7	)

Net Income	$	122		$	190

Basic Earnings per Common Share (Note 6)
Income from continuing operations	$	.70		$	1.16
Discontinued operations		—			(.04	)

Total	$	.70		$	1.12

Diluted Earnings per Common Share (Note 6)
Income from continuing operations	$	.70		$	1.15
Discontinued operations		—			(.04	)

Total	$	.70		$	1.11

Average Common Shares
Basic		174			170
Diluted		175			170
Dividends Declared per Common Share	$	.515		$	.515

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Financial Position


	(Unaudited)
	March 31			December 31
	2005			2004
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	60		$	56
Restricted cash		74			126
Accounts receivable
Customer (less allowance for doubtful accounts of $134 and $129, respectively)		1,157			880
Accrued unbilled revenues		294			378
Other		410			383
Inventories
Fuel and gas		362			509
Materials and supplies		152			159
Assets from risk management and trading activities		423			296
Other		259			209

		3,191			2,996


Investments
Nuclear decommissioning trust funds		593			590
Other		557			558

		1,150			1,148


Property
Property, plant and equipment		18,131			18,011
Less accumulated depreciation and depletion		(7,607	)		(7,520	)

		10,524			10,491


Other Assets
Goodwill		2,067			2,067
Regulatory assets		2,145			2,119
Securitized regulatory assets		1,414			1,438
Notes receivable		486			529
Assets from risk management and trading activities		192			125
Prepaid pension assets		184			184
Other		190			200

		6,678			6,662


Total Assets	$	21,543		$	21,297

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Financial Position


	(Unaudited)
	March 31			December 31
(in Millions, Except Shares)	2005			2004
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	863		$	892
Accrued interest		116			111
Dividends payable		90			90
Accrued payroll		34			33
Income taxes		—			16
Short-term borrowings		439			403
Gas inventory equalization (Note 1)		278			—
Current portion of long-term debt, including capital leases		347			514
Liabilities from risk management and trading activities		537			369
Other		499			581

		3,203			3,009

Other Liabilities
Deferred income taxes		1,164			1,124
Regulatory liabilities		828			817
Asset retirement obligations (Note 1)		930			916
Unamortized investment tax credit		140			143
Liabilities from risk management and trading activities		261			224
Liabilities from transportation and storage contracts		378			387
Accrued pension liability		289			265
Deferred gains from asset sales		386			414
Minority interest		128			132
Nuclear decommissioning		78			77
Other		688			635

		5,270			5,134

Long-Term Debt (net of current portion) (Note 7)
Mortgage bonds, notes and other		5,671			5,673
Securitization bonds		1,345			1,400
Equity-linked securities		173			178
Trust preferred-linked securities		289			289
Capital lease obligations		63			66

		7,541			7,606


Commitments and Contingencies (Notes 5, 8 and 9)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized,174,175,040 and 174,209,034 shares issued and outstanding, respectively		3,309			3,323
Retained earnings		2,415			2,383
Accumulated other comprehensive loss		(195	)		(158	)

		5,529			5,548


Total Liabilities and Shareholders’ Equity	$	21,543		$	21,297

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Cash Flows (Unaudited)


	Three Months Ended
	March 31
(in Millions)	2005			2004
Operating Activities
Net Income	$	122		$	190
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		208			167
Deferred income taxes		51			113
Gain on sale of interests in synfuel projects		(82	)		(49	)
Loss (gain) on sale of assets, net		4			(3	)
Partners’ share of synfuel project losses		(71	)		(36	)
Contributions from synfuel partners		47			17
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		134			(119	)

Net cash from operating activities		413			280


Investing Activities
Plant and equipment expenditures — utility		(172	)		(161	)
Plant and equipment expenditures — non-utility		(26	)		(18	)
Proceeds from sale of interests in synfuel projects		63			26
Proceeds from sale of other assets		2			31
Restricted cash for debt redemptions		52			54
Other investments		(31	)		(26	)

Net cash used for investing activities		(112	)		(94	)


Financing Activities
Issuance of long-term debt		395			-
Redemption of long-term debt		(628	)		(232	)
Short-term borrowings, net		36			134
Issuance of common stock		—			11
Repurchase of common stock		(9	)		—
Dividends on common stock		(90	)		(87	)
Other		(1	)		(2	)

Net cash used for financing activities		(297	)		(176	)


Net Increase in Cash and Cash Equivalents		4			10
Cash and Cash Equivalents at Beginning of the Period		56			54

Cash and Cash Equivalents at End of the Period	$	60		$	64

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Changes in Shareholders’ Equity and
Comprehensive Income (Unaudited)


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

Balance, December 31, 2004		174,209		$	3,323		$	2,383		$	(158	)	$	5,548

Net income		—			—			122			—			122
Dividends declared on common stock		—			—			(90	)		—			(90	)
Repurchase of common stock		(207	)		(9	)		—			—			(9	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(40	)		(40	)
Net change in unrealized losses on investments, net of tax		—			—			—			3			3
Unearned stock compensation and other		173			(5	)		—			—			(5	)

Balance, March 31, 2005		174,175		$	3,309		$	2,415		$	(195	)	$	5,529

The following table displays other comprehensive income (loss) for the three-month period ended March 31:


	2005			2004
(in Millions)
Net income	$	122		$	190

Other comprehensive income (loss), net of tax:
Net unrealized income (losses) on derivatives:
Losses arising during the period, net of taxes of $27 and $2, respectively.		(50	)		(3	)
Amounts reclassified to earnings, net of taxes of $(5) and $1, respectively		10			(2	)

		(40	)		(5	)
Net change in unrealized gain on investments, net of taxes of $(2) and $(2).		3			4

		(37	)		(1	)

Comprehensive income	$	85		$	189

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy 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 2004 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.

Prior to December 2004, DTE Energy did not eliminate amounts, principally within Other Income and Other Deductions, resulting from certain intercompany transactions. The amounts of the transactions are immaterial and had no effect on net income. Previously reported prior period amounts have been adjusted to eliminate those intercompany transactions and are now consistent with the current year’s presentation. We reclassified certain other prior year balances to match the current year’s financial statement presentation.

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

Gains from Sale of Interests in Synthetic Fuel Facilities

Through March 31, 2005, we have sold interests in eight of our nine synthetic fuel production plants, representing approximately 88% of our total production capacity. Proceeds from the sales are contingent upon production levels and the value of Section 29 tax credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 9 for further discussion. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. We recorded $82 million in gains in the first quarter of 2005 from the sale of interests in synthetic fuel facilities compared to $49 million in the first quarter 2004.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectability is assured. The variable component includes an estimate of tax credits allocated to our partners, is subject to refund based on the annual oil price phase out, and is recognized as a gain only when probability of refund is considered remote and collectability is assured. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities. This amount is subject to refund based on the annual oil price phase out. To assess the probability of refund, we use valuation and analyst models that calculate the probability of surpassing the estimated lower band of the phase-out range for the Reference Price of oil for the year. Due to the rise in oil prices, there is a possibility that the Reference Price of oil could reach the threshold at which Section 29 tax credits phase out. While we believe the possibility of phase out is unlikely, we have not met the strict accounting gain recognition criteria that would allow us to recognize the gains on the variable component. During the first quarter of 2005, we deferred $41 million pretax of the variable component of synfuel-related gains for the potential phase-out of synfuel tax credits. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria is met. It is possible that additional gains will be deferred in the second and/or third quarters until there is persuasive evidence that no tax credit phase out will occur. This will result in shifting earnings from earlier quarters to later quarters.

Stock-Based Compensation

We have a stock-based employee compensation plan. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation cost related to stock options is reflected in earnings, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. The recognition provisions under SFAS No. 123, “Accounting for Stock-Based Compensation,” require the recording of compensation expense for stock options equal to their fair value at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and earnings per share if we had recorded compensation expense for options granted under the fair value recognition provisions of SFAS No. 123.


	Three Months Ended
	March 31
(in Millions, except per share amounts)	2005			2004
Net Income as reported	$	122		$	190
Less: Total stock-based expense (1)		(2	)		(2	)

Pro Forma Net Income	$	120		$	188


Earnings Per Share
Basic — as reported	$	.70		$	1.12

Basic — pro forma	$	.69		$	1.11


Diluted — as reported	$	.70		$	1.11

Diluted — pro forma	$	.69		$	1.10


(1)		Expense determined using a Black-Scholes based option pricing model.

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
(in Millions)	2005			2004
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(267	)	$	(157	)
Accrued unbilled receivable		84			50
Accrued GCR revenue		(25	)		(39	)
Inventories		154			260
Accrued/Prepaid pensions		23			23
Accounts payable		(29	)		27
Accrued PSCR refund		(8	)		46
Exchange gas payable		(62	)		(108	)
Income taxes payable		(20	)		(211	)
General taxes		12			(4	)
Risk management and trading activities		64			10
Gas inventory equalization		278			167
Other		(70	)		(183	)

	$	134		$	(119	)

Supplementary cash and non-cash information follows:


	Three Months Ended
	March 31
(in Millions)	2005		2004
Cash Paid for
Interest (excluding interest capitalized)	$	123	$	128
Income taxes	$	1	$	173

Noncash Investing and Financing Activities
Notes received from sale of synfuel projects	$	—	$	83
Common stock contribution to pension plan	$	—	$	170

Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations,” requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to regulated operations, we believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and 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 2005 three-month period follows:



(in Millions)
Asset retirement obligations at January 1, 2005	$	916
Accretion		15
Liabilities settled		(1	)

Asset retirement obligations at March 31, 2005.	$	930

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 March 31	2005			2004			2005			2004
Service Cost	$	16		$	16		$	14		$	11
Interest Cost		43			43			26			23
Expected Return on Plan Assets		(54	)		(52	)		(17	)		(14	)
Amortization of:
Net loss		17			16			15			10
Prior service cost		2			2			(1	)		(1	)
Net transition liability		—			—			2			2

Net Periodic Benefit Cost	$	24		$	25		$	39		$	31

Gas in Inventory

Gas inventory at MichCon is priced on a last-in, first-out (LIFO) basis. In anticipation that interim inventory reductions will be replaced prior to year end, the cost of gas of net withdrawals from inventory is recorded at the estimated average purchase rate for the calendar year. The excess of these charges over the LIFO cost is credited to the gas inventory equalization account. During interim periods when there are net injections to inventory, the equalization account is reversed.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Medicare Act Accounting

In May 2004, FASB Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” was issued on accounting for the effects of the Medicare Act. In the second quarter of 2004, we adopted FSP No. 106-2, retroactive to January 1, 2004 and as a result earnings for the first quarter of 2004 have been restated. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $95 million and was accounted for as an actuarial gain. The effects of the subsidy reduced net postretirement costs by $4 million in the first quarter of 2004.

Stock Based Payments

In December 2004, the FASB issued SFAS No. 123-R, “Stock Based Payments,” which established the accounting for transactions in which an entity exchanges equity instruments for goods or services. SFAS No. 123-R was effective for interim or annual periods beginning after June 15, 2005 with earlier adoption encouraged. In April 2005, the U.S. Securities and Exchange Commission delayed the effective date by requiring implementation beginning in the next fiscal year that begins after June 15, 2005. We have completed a preliminary review and based on historical levels of stock based payments we estimate that the new standard will reduce reported earnings by approximately $5 million to $10 million per year.

Accounting for Conditional Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” FIN 47 seeks to clarify the requirement to record liabilities stemming from a legal obligation to perform asset retirement activities on fixed assets when that retirement is conditioned on a future event. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company is currently assessing the effects of this interpretation, and has not yet determined the impact on the consolidated financial statements.

NOTE 3 — DISPOSITIONS

Southern Missouri Gas Company – Discontinued Operation

We own Southern Missouri Gas Company (SMGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the SFAS No. 144 criteria of an asset “held for sale,” and we have reported its operating results as a discontinued operation. We recognized a net of tax impairment loss of approximately $7 million in 2004, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and it is anticipated that the transaction will close in the second quarter of 2005. SMGC had assets of $9 million and liabilities of $35 million at December 31, 2004.

NOTE 4 — CONTRACT MODIFICATION/TERMINATION

In February 2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and terminated a related long-term gas exchange (storage) agreement, effective March 31, 2004. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season. The agreements were at rates that were not reflective of current market conditions and had been fair valued under accounting principles generally accepted in the U.S. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately $75 million as of December 31, 2003. As a result of the contract modification and termination, we recorded an adjustment to the net liability increasing earnings in the 2004 first quarter by $48 million, net of taxes.

NOTE 5 — REGULATORY MATTERS

Electric Rate Restructuring Proposal

On February 4, 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies that are part of its current pricing structure. The proposal would adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, commercial and industrial rates would be lowered, but residential rates would increase over a five-year period beginning in 2007. The MPSC anticipates that this proceeding will be completed in time to have new rates in effect no later than January 1, 2006.

Other Postretirement Benefits Costs Tracker

On February 10, 2005, Detroit Edison filed an application, pursuant to the MPSC’s November 2004 final rate order, requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. This mechanism would recognize differences between cost levels collected in rates and the actual costs under current accounting rules as regulatory assets or regulatory liabilities with an annual reconciliation proceeding before the MPSC.

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

In accordance with the MPSC’s direction in the Detroit Edison’s November 2004 final rate order, on March 31, 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. The combined proceeding will provide a comprehensive true-up of the 2004 PSCR and production fixed cost stranded cost calculations, including treatment of the Company’s third party wholesale sales revenues. In the filing, Detroit Edison recommended the following distribution of the $218 million of third party wholesale sale revenues; $91 million to offset PSCR fuel expense, $74 million to offset 2004 production operation and maintenance expense, $40 million to offset 2004 PSCR expense and $13 million to offset 2004 production fixed cost stranded costs. Based upon this allocation of third party wholesale sales revenues, Detroit Edison recommends the return of approximately $8 million in over-collections to its PSCR customers and the recovery of approximately $99 million in net stranded costs from its electric Customer Choice customers. Included with the application was the filing of a motion for a temporary interim order requesting the continuation of the existing electric Customer Choice transition charges until a final order is issued.

DTE2 Accounting Application

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. The new information systems are replacing systems that are approaching the end of

their useful lives. We expect the benefits of DTE2 to include lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize DTE2 costs, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In March 2005, a settlement agreement was reached with all parties to this proceeding providing for the deferral of up to $60 million of certain DTE2 costs that would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. In addition, DTE2 costs recorded as plant assets will be amortized over a 15-year period. In April 2005, the MPSC approved the settlement agreement.

Power Supply 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 NOx emission allowance costs. Detroit Edison self-implemented a factor of a negative 2.00 mills per kWh on January 1, 2005. At March 31, 2005, Detroit Edison has recorded an under-recovery of approximately $14 million related to the 2005 plan year. The Michigan Attorney General has filed a motion for summary disposition of this proceeding based on arguments that the PSCR statute requires a fixed 48-month PSCR factor. We cannot predict the nature or timing of actions the MPSC will take on this motion.

Gas Rate Case

Rate Request — In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requested an overall increase in base rates of $194 million per year beginning January 1, 2005. MichCon requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004. The final rate request was subsequently revised to $159 million.

MPSC Final Rate Order – On April 28, 2005, the MPSC issued an order for final rate relief. The MPSC determined that the base rate increase granted to MichCon should be $61 million annually effective April 29, 2005. This amount is an increase of $26 million over the $35 million in interim rate relief approved in September 2004. The rate increase was based on a 50% debt and 50% equity capital structure and an 11% rate of return on common equity.

The MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC. The MPSC also approved the deferral of the non-capitalized portion of the negative pension expense. MichCon will record a regulatory liability in its financial statements for any negative pension costs as determined under generally accepted accounting principles. In addition, the MPSC approved a one-way tracker which provided for $25 million which is refundable in the event that the funds are not expended for safety and training operation and maintenance expenses.

The MPSC order reduces MichCon’s depreciation rates, and the related revenue requirement associated with depreciation expense by $14.5 million with no impact on net income.

The MPSC did not allow the recovery of approximately $25 million of costs allocated to MichCon that were incurred by DTE Energy as a result of the acquisition of MCN Energy.

The MPSC order also resulted in the disallowance of computer system and equipment costs and adjustments to environmental regulatory assets and liabilities. The MPSC disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. MichCon impaired this asset by approximately $42 million in the first quarter of 2005. This impairment is not reflected at DTE Energy since this disallowance was previously reserved at the time of the MCN acquisition in 2001. The MPSC disallowed approximately $6 million of certain computer equipment and related depreciation. The MPSC order also disallowed recovery of certain internal labor and legal costs related to remediation of manufactured gas plants of approximately $6 million.

Gas Cost Recovery Proceedings

2002 Plan Year — In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per thousand cubic feet (Mcf) for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset was subject to the 2002 GCR reconciliation process. In March 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year. We recorded a $26.5 million reserve in 2003 to reflect the impact of this order.

MichCon’s 2002 GCR reconciliation case was filed with the MPSC in February 2003. The Staff and various intervening parties in this proceeding sought to have the MPSC disallow an additional $26 million, representing unbilled revenues at December 2001. One party also proposed the disallowance of half of an $8 million payment made to settle Enron bankruptcy issues. The other parties to the case recommended that the Enron bankruptcy settlement be addressed in the 2003 GCR reconciliation case. In April 2005, the MPSC issued an order in the 2002 GCR reconciliation case affirming the order in the 2002 GCR plan case disallowing $26.5 million related to the use of storage gas in 2001. The April 2005 order also disallowed the additional $26 million representing unbilled revenues at December 2001. We recorded the impact of the disallowance in the first quarter of 2005. The MPSC agreed that the $8 million related to the Enron issue be addressed in the 2003 GCR reconciliation case. MichCon included this item in testimony in the 2003 GCR reconciliation filed in February 2004 and the Staff has recommended that MichCon be allowed to recover the entire $8 million related to the Enron issue.

2005-2006 Plan Year — In December 2004, MichCon filed its 2005-2006 GCR plan case proposing a maximum GCR factor of $7.99 per Mcf. The plan includes quarterly contingent GCR factors. These contingent factors allow MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery. In April 2005, the MPSC issued an order recognizing that Michigan law allows MichCon to self-implement its quarterly contingent factors. Approval of the contingent factors will be determined in the MPSC’s final order in this case.

Other

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

NOTE 6 — EARNINGS PER SHARE

We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options,

vesting of non-vested stock awards, and the issuance of performance share awards. A reconciliation of both calculations is presented in the following table:


	Three Months Ended
	March 31
(in Millions, except per share amounts)	2005		2004
Basic Earnings Per Share
Income from continuing operations	$	122	$	197

Average number of common shares outstanding		173.7		169.9

Income per share of common stock based on weighted average number of shares outstanding	$	.70	$	1.16


Diluted Earnings Per Share
Income from continuing operations	$	122	$	197

Average number of common shares outstanding		173.7		169.9
Incremental shares from stock based awards		.9		.5

Average number of dilutive shares outstanding		174.6		170.4

Income per share of common stock assuming issuance of incremental shares	$	.70	$	1.15

Options to purchase approximately 100,000 shares of common stock in 2005, and one million shares of common stock in 2004, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 7 — LONG-TERM DEBT

In February 2005, Detroit Edison issued $400 million of senior notes in two series, $200 million of 4.8% series due 2015 and $200 million of 5.45% series due 2035. The proceeds were used to redeem the $385 million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

Also in February 2005, Detroit Edison redeemed $76 million of 7.5% senior notes and $100 million of 7.0% remarketed secured notes, which matured February 2005.

NOTE 8 — DERIVATIVE INSTRUMENTS

Commodity Price Risk

Our Energy Services and Biomass businesses generate Section 29 tax credits. Additionally, through December 2004, Energy Services has sold interests in eight of its nine synthetic fuel production plants. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 9 for further discussion.

To manage our exposure in 2005 and 2006 to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full years 2005 and 2006 average New York Mercantile Exchange (NYMEX) trading prices of oil in relation to the strike prices of each option. If the average NYMEX prices of oil in 2005 and 2006 are less than approximately $56 per barrel, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $56 per barrel, the derivatives will yield a payment equal to the excess of the average NYMEX price over $56 per barrel, multiplied by the number of barrels covered, up to a maximum price of approximately $68 per barrel. The agreements do not qualify for hedge

accounting and, as a result, changes in the fair value of the options are recorded currently in earnings. We recorded a mark to market gain during the 2005 first quarter that increased 2005 synfuel gains by $54 million pre-tax. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and therefore included in the “Asset gains and losses, net” line item in the consolidated statement of operations.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Synthetic Fuel Operations

We partially or wholly own nine synthetic fuel production facilities. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 tax credits.

Oil Prices — To reduce U.S. dependence on imported oil, the Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides a natural market for these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil. Due to recent increased volatility, the Reference Price per barrel of oil has been $4-$7 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2005, we estimate that the threshold price at which the tax credit would begin to be reduced is $52 per barrel and would be completely phased out if the Reference Price reached $66. Through March 31, 2005, the NYMEX closing price of a barrel of oil has averaged $50, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to a $43 to $46 Reference Price (assuming that such price was to continue for the entire year and the difference between wellhead and NYMEX ranges from $4 — $7 per barrel). We cannot predict with any accuracy the future price of a barrel of oil.

Numerous recent events have increased domestic crude oil prices, including terrorism, storm-related supply disruptions and worldwide demand. If the credit is reduced or eliminated in future years, our financial statements would be negatively impacted. We continue to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy. To manage our exposure to oil prices in 2005 and 2006, we entered into oil-related derivative contracts. See Note 8 for further discussion.

Environmental

Air — The EPA issued ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, carbon dioxide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $580 million through December 2004, and estimates that it will spend up to $100 million in 2005 and incur up to $1.8 billion of additional future capital expenditures through 2018 to satisfy both the existing and proposed new control requirements. Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure, in excess of current depreciation levels, could be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end on December 31, 2005 upon MPSC authorization. Under PA 141 and the MPSC’s November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

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 five to seven years in additional capital expenditures for Detroit Edison.

Contaminated Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Enterprises (MichCon and Citizens) owns, or previously owned, 18 such former manufactured gas plant (MGP) sites. During the mid-1980’s, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. The existence of these sites and the results of the environmental investigations have been reported to the Michigan Department of Environmental Quality (MDEQ).

Enterprises is remediating eight of the former MGP sites and conducting more extensive investigations at five other former MGP sites. Enterprises received MDEQ closure of one site, and a determination that it is not a responsible party for three other sites. Enterprises received closure from the EPA in 2002 for one site.

In 1984, Enterprises established a $12 million reserve for costs associated with environmental investigation and remediation activities. During 1993, MichCon received MPSC approval of a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites in excess of this reserve. Enterprises employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies. As a result of these studies, Enterprises accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. In early December 2004, Enterprises retained multiple environmental consultants to estimate the projected cost to remediate each MGP facility. The results of the evaluation indicated that the MGP reserve should be set at $24 million.

During 2004, Enterprises spent approximately $2 million investigating and remediating these former MGP sites. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and, therefore, have an effect on the Company’s financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

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 cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

Guarantees

In certain circumstances we enter into contractual guarantees. We may guarantee another entity’s obligation in the event it fails to perform. We may provide guarantees in certain indemnification agreements. Finally, we may provide indirect guarantees of the indebtedness of others. Below are the details of specific material guarantees we currently provide. Our other guarantees are not individually material and total approximately $38 million at March 31, 2005.

Sale of Interests in Synfuel Facilities

We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities. The guarantees cover general commercial, environmental and tax-related exposure and will survive until 90 days after expiration of all applicable statute of limitations, or indefinitely,

depending on the nature of the guarantee. We estimate that our maximum liability under these guarantees at March 31, 2005 totals $902 million.

Parent Company Guarantee of Subsidiary Obligations

We have issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $422 million at March 31, 2005. This estimated amount fluctuates based upon the provisions and maturities of the underlying agreements.

Personal Property Taxes

Prior to 1999, Detroit Edison, MichCon and other Michigan utilities 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 have taken legal action attempting to prevent the STC from implementing the new valuation tables and have 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 its 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. Detroit Edison and MichCon have filed motions and the MTT agreed to place their cases in abeyance pending the conclusion of settlement negotiations being conducted by State of Michigan Treasury officials. On February 14, 2005, MTT issued a scheduling order that lifts the prior abeyances in a significant number of Detroit Edison and MichCon appeals. The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison and MichCon continue to record property tax expense based on the new tables. Detroit Edison and MichCon will continue through settlement or litigation to seek to apply the new tables retroactively and to ultimately resolve the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. To the extent that settlements cannot be achieved with the jurisdictions, litigation regarding the valuation of utility property will delay any recoveries by Detroit Edison and MichCon.

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. During the first quarter of 2005 we purchased $12 million of steam and electricity. For the full year 2004, we purchased $42 million of steam and electricity. We estimate steam and electric purchase commitments through 2024 will not exceed $472 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.

In 2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and terminated a related long-term gas exchange (storage) agreement. Under

the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season. The agreements were at rates that were not reflective of current market conditions and had been fair valued under accounting principles generally accepted in the U.S. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately $75 million as of December 31, 2003. As a result of the contract modification and termination, we recorded an adjustment to the net liability increasing 2004 earnings by $48 million, net of taxes.

At December 31, 2004, we have entered into 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 $7.3 billion through 2027. We also estimate that 2005 base level capital expenditures will be $1.1 billion. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

We purchase and sell electricity, gas, coal and coke from and to numerous companies operating in the steel, automotive, energy and retail industries. Several customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of 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 in the period they are resolved.

Other

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 5 for a discussion of contingencies related to Regulatory Matters.

NOTE 10 — SHORT-TERM CREDIT ARRANGEMENTS & BORROWINGS

MichCon currently has an $81.25 million, three-year unsecured credit agreement originally entered into in October 2003, and a $243.75 million, five-year unsecured revolving credit facility entered into in October 2004. These credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for MichCon’s commercial paper program. Borrowings under the facilities are available at prevailing short-term interest rates. Among other things, the agreements require MichCon to maintain an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1 for each twelve-month period ending on the last day of March, June, September and December of each year.

As a result of the non-recurring accounting adjustments that were required due to the MPSC gas rate orders issued on April 28, 2005, MichCon did not meet the EBITDA to interest ratio at March 31, 2005. The lenders have agreed to amend the credit facilities to exclude the EBITDA to interest ratio for the first quarter of 2005. At March 31, 2005 and the date of the amendments, MichCon does not have any indebtedness under the credit facilities or any commercial paper outstanding.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
DTE Energy Company

We have reviewed the accompanying condensed consolidated statement of financial position of DTE Energy Company and subsidiaries as of March 31, 2005, and the related condensed consolidated statements of operations and cash flows for the three-month periods ended March 31, 2005 and 2004, and changes in shareholders’ equity and comprehensive income for the three-month period ended March 31, 2005 and the three-month periods ended March 31, 2005 and 2004, respectively. These interim financial statements are the responsibility of DTE Energy Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated statement of financial position of DTE Energy Company and subsidiaries as of December 31, 2004, and the related consolidated statements of operations, cash flows and changes in shareholders’ equity and comprehensive income for the year then ended (not presented herein); and in our report dated March 15, 2005 (August 4, 2005 as to Note 16) (which report includes an explanatory paragraph relating to the change in the methods of accounting for asset retirement obligations, energy trading contracts and gas inventories in 2003 and goodwill and energy trading contracts in 2002), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated statement of financial position as of December 31, 2004 is fairly stated, in all material respects, in relation to the consolidated statement of financial position from which it has been derived.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
May 10, 2005 (August 4, 2005 as to Note 11)


	Three Months Ended
	March 31
(in Millions)	2005			2004
Operating Revenues

Electric Utility	$	990		$	886
Gas Utility		852			729
Non-utility Operations:
Power and Industrial Projects		311			255
Unconventional Gas Production		16			17
Fuel Transportation and Marketing		316			305

		643			577

Corporate & Other		10			14
Reconciliation & Eliminations		(180	)		(113	)

Total	$	2,315		$	2,093


Net Income (Loss)

Electric Utility	$	55		$	44
Gas Utility		13			71
Non-utility Operations:
Power and Industrial Projects		68			35
Unconventional Gas Production		1			1
Fuel Transportation and Marketing		(10	)		61

Corporate & Other		(5	)		(15	)

Income from Continuing Operations
Utility		68			115
Non-utility		59			97
Corporate & Other		(5	)		(15	)

		122			197

Discontinued Operations		—			(7	)