DTE Energy (DTE) CORRESP Correspondence with SEC

DTE Energy Company
2000 2nd Ave., Detroit, MI 48226-1279

August 30, 2007

VIA ELECTRONIC TRANSMISSION (EDGAR)

Michael Moran
Branch Chief Accountant
Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549

Re: DTE Energy Company
Form 10-K for the year ended December 31, 2006
Filed March 1, 2007
File No. 1-11607

Dear Mr. Moran:

Set forth below are the responses of DTE Energy Company to the comments of the staff of the Securities and Exchange Commission (the “SEC” or the “Commission”) contained in its letter to the Company dated July 26, 2007 (the “Comment Letter”). References to “DTE,” “we,” “us,” “our,” or the “Company” in this letter mean DTE Energy Company and its consolidated subsidiaries. Capitalized terms used but not defined in this letter have the meanings given to such terms in our Form 10-K for the year ended December 31, 2006.

For convenience of reference, each SEC staff comment is reprinted in italics, numbered to correspond with the paragraph numbers assigned in the Comment Letter, and is followed by the corresponding response.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, page 27

1. Please explain to us if the holding company is subject to any limitations with respect to its ability to pay dividends. If so, then please disclose the amount of retained earnings or net income restricted. Further, please advise or disclose separately the amounts of restricted net assets for unconsolidated and consolidated subsidiaries as of the end of the most recent fiscal year. See Rule 4-08(e) of Regulation S-X.

August 30, 2007
Page 2

Response:

Certain of DTE Energy Company’s (the “Holding Company”) credit facilities contain a provision requiring the Holding Company to maintain a ratio of consolidated debt to capitalization equal to or less than 0.65:1, which has the effect of limiting the amount of dividends the Holding Company can pay in order to maintain compliance with this provision. The effect of this provision as of December 31, 2006 was to restrict $189 million, out of total retained earnings of $2.6 billion, from payment as dividends. There are no other effective limitations with respect to the Holding Company’s ability to pay dividends. In future filings, beginning with the 2007 Form 10-K, we will disclose the amount of retained earnings which is restricted.

Pursuant to Rule 4-08(e) of Regulation S-X, the Company did not disclose the amounts of restricted net assets for unconsolidated and consolidated subsidiaries as of the end of 2006 due to the fact that the restricted net assets of consolidated and unconsolidated subsidiaries and the Company’s equity in the undistributed earnings of 50 percent or less owned persons accounted for by the equity method together did not exceed 25 percent of consolidated net assets of DTE Energy Company and consolidated subsidiaries as of December 31, 2006. To the extent such amounts exceed the 25 percent threshold in the future, we will disclose the amounts in future Company filings with the Commission.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 30

Utility Operations, page 31

2. We assume the difference in the allowance for doubtful accounts referenced here ($123 and $98 for 2006 and 2005, respectively) and on balance sheet ($170 and $136 for 2006 and 2005, respectively) represent non-utility operations. In this regard, please provide a reconciliation for our review.

Response:

The amounts on page 31 represent the combined allowance for doubtful accountsexpense for the respective years for our primary utilities, Detroit Edison and MichCon. In future filings, we will modify the wording to more clearly state that the amounts are expense, not the balances of the reserves. Please see the table below for a reconciliation of the amounts shown on page 31 in the Utility Operations MD&A overview discussion to the allowance for doubtful accounts as shown on the balance sheet and as detailed on Schedule II in the 2006 Form 10-K.

August 30, 2007
Page 3

As Reported on Schedule II	Year Ending December 31
(in Millions)	2006			2005
Allowance for Doubtful Accounts — Beginning of period	$	136		$	129
Charged to costs and expenses per Schedule II		120			106
Charged to other accounts (1)		7			9
Deductions (2)		(93	)		(108	)
Allowance for Doubtful Accounts — End of Period (3)	$	170		$	136
Reconciliation to expense reported on Page 31
Expense charged to Allowance for Doubtful Accounts per Schedule II	$	120		$	106
Expense of match to low-income assistance customers		10			—
Proceeds from sales of previously written off accounts receivable		(2	)		(6	)
Non-utility doubtful accounts expense		(1	)		(2	)
Other Accounts Receivable		(4	)		—
Allowance for Doubtful Accounts expense — utilities (per page 31)	$	123		$	98

(1)	Collection of accounts previously written off
(2)	Uncollectible accounts written off
(3)	December 31, 2006 balance consists of $168 million ($96 million — MichCon and $72 million — Detroit Edison) for utility operations and $2 million for non-utility operations. December 31, 2005 balance consists of $132 million ($78 million — MichCon and $54 million — Detroit Edison) for utility operations and $4 million for non-utility operations.

Proceeds from the sales of previously written off accounts receivable were recorded as recoveries through uncollectible expense. In addition, in 2006 Detroit Edison and MichCon incurred expense representing a match of funds provided to utility customers from a State of Michigan low-income assistance program. These funds are used by low-income customers to pay outstanding utility bills. These amounts were charged directly to expense without passing through the allowance for doubtful accounts.

Beginning in 2006, a change in methodology was made to reflect a more comprehensive view in the presentation of Schedule II to include the allowance for doubtful accounts for other receivables. In prior years, the amounts in Schedule II included only the allowance for doubtful accounts for customer accounts receivable. The allowance for doubtful accounts for other accounts receivable was approximately $3 million at December 31, 2005.

August 30, 2007
Page 4

Power and Industrial Projects, page 49

3. Please describe the changes in circumstances that led to the impairment of the gas-fired generating plant. In this regard, provide to us a summary of the impairment test that led to the $42 million charge. In addition, please provide to us a summary of the impairment tests used to support the carrying values of the other owned gas-fired generating plants.

Response:

Overview

The Company monitors events or changes in circumstances that may affect the carrying value of its long-lived assets. Assets held for use are tested for recoverability when events or changes in circumstances indicate that their carrying value may not be recoverable.

DTE, through its non-utility subsidiaries, owned several merchant gas-fired generating plants that were used to meet peak demand needs within the MISO region. During the second half of 2006, DTE reviewed its long-term core strategy for its non-utility businesses, which included a review of its merchant generation assets. In conjunction with this review, DTE senior management contemplated the possibility of selling or restructuring these facilities as part of a strategy to exit the merchant generation business, which it discussed with the DTE Board of Directors in September 2006. As of September 30, 2006, no “formal” proposal had been developed, or approved by the Board of Directors. However, as directed by the Board of Directors, DTE began developing a divestiture or restructuring strategy for these assets.

The decision to divest or restructure the merchant generation assets, as well as other events or changes in circumstances as discussed further below, triggered the need to analyze the following generation assets for impairment during the second half of 2006.

River Rouge

The 225 MW gas-fired generating plant located in River Rouge, Michigan (“River Rouge”) is a single cycle natural gas peaking unit which was previously listed on MISO. In conjunction with the change in strategic direction discussed above, during the third quarter of 2006 River Rouge was delisted from MISO and ceased providing capacity to the power grid as the facility was not able to competitively price to the market without the infusion of additional capital investment. River Rouge had historically operated as a peaking unit. However, MISO seeks peaking units in its generation fleet that can be quickly cycled on and off to meet peak demands. Due to its age and design, River Rouge takes up to 24 hours for the initial cycle on, making it difficult and costly for MISO to dispatch River Rouge to serve peak demands for electricity. As a result, River Rouge was delisted from serving as a peaking unit in the MISO fleet, which was a significant adverse change in how River Rouge could be used. This event, which eliminated potential future revenues and related cash flows, coupled with losses incurred to maintain the

August 30, 2007
Page 5

facility, led DTE to believe that the carrying amount of River Rouge’s assets might not be recoverable.

An impairment analysis was performed in the third quarter 2006 in accordance with SFAS No. 144 guidance for long-lived assets. DTE considered probability weighted scenarios which included the disposal of River Rouge at the estimated salvage value, the continued use of the asset by DTE or a sale to a third party. River Rouge is a non-regulated merchant plant and is located on a larger site with a base-load generation facility owned by Detroit Edison. Senior management determined that future operation of River Rouge in its current condition was unlikely (and subsequently the plant has not run), and additional capital (which would be necessary to improve the plant’s design and efficiency) was not expected to be invested in River Rouge for the foreseeable future. Additionally, it was determined that a sale to a third party was impracticable due to River Rouge’s age and co-location with Detroit Edison facilities. Therefore, the use and sale scenarios were eliminated, leaving only the disposal of River Rouge at the estimated salvage value of $3 million. The write-down of the net book value of $45 million to $3 million resulted in the $42 million impairment loss shown in the “Asset (gains) and losses, reserves and impairments, net” line of the Consolidated Statement of Operations for the year ended December 31, 2006.

Other Gas-Fired Generating Plants

In addition to River Rouge, DTE had a 50% ownership interest in a gas-fired generating plant (“Crete”) and a 100% ownership interest in two other gas-fired generating plants (“Georgetown” and “East China”) as of December 31, 2006. The Crete facility, located in Will County, Illinois, consists of four single cycle GE combustion turbines, with combined generating capacity of 320 MW (DTE-owned capacity is 160 MW). The Georgetown facility, located in Indianapolis, Indiana, is comprised of an 80 MW, single cycle, natural gas-fired peaking unit. The East China facility, located in East China Township, Michigan, includes four single cycle GE combustion turbines, with combined generating capacity of 320 MW.

As discussed above, DTE contemplated the possibility of selling or restructuring these three facilities and held discussions with the DTE Board of Directors in September 2006 regarding its strategy for these assets. Through this review, it was believed to be more likely than not (greater than 50% likelihood) that the facilities would be sold. The decision to potentially divest these three facilities qualified as a change in circumstances that indicated that the carrying amounts of these assets may not be recoverable. Therefore, the Company analyzed the assets for impairment as of September 30, 2006.

50% Owned Plant

Crete

DTE uses the equity method to account for its investment in Crete. An impairment analysis for the equity investment was performed in accordance with APB No. 18, paragraph 19(h) guidance,

August 30, 2007
Page 6

whereby the net carrying value of DTE’s investment was compared to its estimated fair value.

To determine the fair value, the Company utilized a discounted cash flow methodology and calculated a probability weighted value based upon alternative courses of action for Crete. The first scenario assumed that Crete would be held and used. The cash flows in the first scenario were based on revenues using contracted rates during the term of the existing sales contract, which expires in May 2008. Subsequent to the existing sales contract period, cash flows were based on probability weighting three capacity price scenarios (mid, high, and low) in Crete’s independent system operator (“ISO”) region. The second scenario utilized market comparable sale transactions in developing a market value approach to value the asset (near term sale). The “market” approach used the average of two market transactions from the same region for capacity-type contracts which provided evidence of fair value.

The following shows the computation, based on the probability of the alternative courses of action:

($ in millions)
Course of Action	DCF		Probability		Expected DCF
Hold and Use	$	33		45%	$	15
Near Term Sale		35		55%		19
					$	34

The expected fair value of $34 million was compared to an investment carrying amount of $66 million. The resulting impairment charge of $32 million was recognized for the year ended December 31, 2006. Consistent with reporting for equity method earnings, this charge was included in the “Other (income) and deductions” section of the Consolidated Statement of Operations.

In July 2007, DTE entered into an agreement to sell its interest in Crete for $37 million. The sale is subject to regulatory approval and is expected to close in the second half of 2007.

100% Owned Plants

Our Georgetown and East China facilities were tested separately for impairment in the third quarter of 2006 in accordance with SFAS No. 144, which requires that the asset be assessed for impairment at the lowest level of identifiable cash flows. The lowest identifiable level of cash flows is at the peaker facility level; therefore, each facility was separately tested. In order to test the recoverability of the carrying amounts of the two facilities, undiscounted after-tax cash flows over each asset’s remaining service potential were calculated in accordance with Step 1 of the SFAS No. 144 impairment test.

August 30, 2007
Page 7

Georgetown

A probability weighted value based upon alternative courses of action for Georgetown was used to determine expected value at September 30, 2006. Two scenarios were considered. The hold and use scenario represented the undiscounted after-tax cash flows using projected revenues based upon the price projections for Georgetown’s ISO region. The near term sale scenario used the average of two market transactions from the same region to determine fair value. The results of the weighting are as follows:

($ in millions)						Expected
	Undiscounted					Undiscounted
Course of Action	Cash Flows		Probability			Cash Flows
Hold and Use	$	25		45	%	$	11
Near Term Sale		21		55	%		12
Total Expected Value				100	%		23
Net Book Value							23
Expected Value in excess of Net Book Value						$	0

No impairment condition existed as of September 30, 2006.

In December 2006, Georgetown met the SFAS No. 144 criteria of an asset “held for sale.” Indicative bids received in the marketing process, which occurred in late 2006, approximated Georgetown’s carrying value, a further indication that the carrying value was recoverable. As discussed in Note 4 of the Notes to the Consolidated Financial Statements in our 2006 Form 10-K, in February 2007 DTE entered into an agreement to sell the facility. The sale received regulatory approval and closed in July 2007, resulting in gross proceeds of $23 million, which approximated net book value.

East China

Management’s decision to begin developing a divestiture or restructuring strategy for its non-regulated peaker assets necessitated an impairment analysis to be performed for the East China facility.

For the analysis, DTE identified and considered several scenarios. In developing the scenarios, DTE also considered the Michigan Capacity Needs Report issued by the MPSC in January 2006 and the internally-generated integrated resource plan (“IRP”) analysis, both of which forecasted electricity supply shortages over the next several years. The Michigan Capacity Needs Report predicted capacity shortages in Michigan over the next 3-5 years and called for approximately 1,300 MWs of new peaker capacity by 2010 to alleviate the projected shortages. Detroit Edison, in its main electric rate case (No. U-15244), included its IRP with an estimate of need for peaking capacity over the 2011-2012 timeframe.

August 30, 2007
Page 8

With these considerations in mind, DTE included a scenario in the impairment analysis that would involve transferring East China to Detroit Edison at the end of East China’s existing sales contract term in 2010. DTE identified two alternative approaches under the transfer scenario. The first assumed a transfer price at the estimated replacement cost for the facility. The second assumed a transfer price based on comparable transaction values. These alternative approaches to model the value ascribed upon the transfer of the facility to Detroit Edison were considered in anticipation of the valuation methodologies that the MPSC would require if the transfer to the utility were to occur.

Alternatively, if DTE were unable to transfer the facility, management expected it would hold and use this facility, which is located in the Detroit Edison service territory. The hold and use scenario represented the undiscounted after-tax cash flows assuming the current capacity contract through 2010 and pricing projections for East China’s ISO region thereafter.

While disposition of all the peaker facilities was discussed, the likelihood of a sale of East China to a third party in the near term was considered small due to the future capacity needs identified by Detroit Edison, and therefore, a near-term sale scenario was not included in the analysis.

The undiscounted after-tax cash flows over the remaining service potential were calculated to test the recoverability of the carrying value, consistent with SFAS No. 144. DTE used a probability weighted methodology, assuming the asset was held and used or transferred to Detroit Edison.

A summary of the impairment test as of December 31, 2006, assuming a transfer at the estimated replacement cost, is presented as follows:

($ in millions)						Expected
	Undiscounted					Undiscounted
Course of Action	Cash Flows		Probability			Cash Flows
Hold and Use	$	168		45	%	$	76
Asset Transfer to Detroit Edison		141		55	%		77
Total Expected Value				100	%		153
Net Book Value							119
Expected Value in excess of Net Book Value						$	34

August 30, 2007
Page 9

A summary of the impairment test as of December 31, 2006, assuming a transfer price based on comparable transaction values, is presented as follows:

($ in millions)						Expected
	Undiscounted					Undiscounted
Course of Action	Cash Flows		Probability			Cash Flows
Hold and Use	$	168		45	%	$	76
Asset Transfer to Detroit Edison		112		55	%		62
Total Expected Value				100	%		138
Net Book Value							119
Expected Value in excess of Net Book Value						$	19

The results of the analyses indicated that the expected value, assuming a transfer to Detroit Edison based on estimated replacement cost or comparable transaction value, exceeded the net book value of $119 million by $34 million and $19 million, respectively. Therefore, no impairment condition existed for the year ended December 31, 2006.

Note 7 – Nuclear Operations, page 104

4.	Please explain to us the regulatory requirements with respect to the investment oversight of the NDT assets. Furthermore, explain to us how you view securities held in the NDT under SFAS no. 115; e.g. trading, available-for-sale or held to maturity.
5.	Please tell us whether there are any unrealized losses on available-for-sale securities held by the NDT. Prospectively, please provide the disclosures required by SFAS no. 115 and EITF Issue no. 03-01 with respect to the NDT assets. Please show us what your disclosure will look like.

Response:

Securities held in the nuclear decommissioning trusts (“NDT”) are classified as available-for-sale in accordance with SFAS No. 115 guidance.

The Company has appointed internal trust committees to oversee the NDTs. The committees approve investment policies and procedures and review results periodically, but do not actively manage the investments in the trusts. Instead, the internal committees direct the external trustee and investment manager to invest the NDT funds within established investment guidelines. According to the terms of its agreement with Detroit Edison, the trustee and investment manager have the unrestricted authority, within the established guidelines, to buy or sell an investment at any time without prior Company approval. Therefore, the Company does not have control over the investments in the NDTs.

August 30, 2007
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The three governmental sources of regulation relating to the investment oversight over NDT assets include the NRC, FERC and MPSC. The NRC defers to the MPSC and the FERC regarding specific investment guidelines, or in the absence of such guidelines, requires the “prudent investor” standard. For regulated utilities such as Detroit Edison, the NRC recommends, but does not require, that an investment manager associated with the trust be an independent third party. The MPSC does not currently have investment guidelines nor does it restrict investments in any asset classes.

The small portion (< 2%) of Detroit Edison’s NDT funds subject to FERC regulation are governed by the FERC mandate that the funds be managed externally by an independent third party under the “prudent investor” standard. FERC rules also state that assets subject to FERC oversight may not be directly invested in any securities of the public utility that owns the associated nuclear facility or in that public utility’s affiliates, associates, successors or assigns.

There were both unrealized gains and losses on available-for-sale securities held by the NDTs during 2006. As Detroit Edison does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, any unrealized losses are considered to be “other than temporary” impairments. This conclusion is in accordance with the guidance found in FSP No. 115-1 as further clarified by SEC Staff Accounting Bulletin Topic 5.M. We had been advised that this guidance was confirmed in meetings that occurred around year-end 2006 between representatives of the utility industry and the staff of the SEC’s Office of the Chief Accountant in the context of nuclear decommissioning trusts.

Detroit Edison currently recovers funds for Fermi 2 decommissioning through a revenue surcharge to customers approved by the MPSC. The amounts recovered from customers are deposited in the Fermi 2 NDTs to fund decommissioning. The Fermi 2 NDTs meet the criteria for application of SFAS No. 71, therefore the offset to the adjustment to market value for unrealized gains and losses is recorded to a regulatory asset account. The Fermi 2 NDTs had unrealized losses of $10 million as of December 31, 2006 which were reflected in the regulatory asset account.

The funding of the decommissioning of Fermi 1 is the responsibility of Detroit Edison and is not recovered from customers through the surcharge mechanism, therefore there is no corresponding regulatory asset treatment for Fermi 1 mark to market adjustments. Pursuant to SFAS No. 115 and the assets’ classification as available-for-sale, unrealized gains are recorded in other comprehensive income, net of tax. Unrealized losses are considered to be “other than temporary” impairments and are recognized in earnings immediately. Detroit Edison recognized a charge of $244,000 for unrealized losses on available-for-sale securities held by the Fermi 1 NDT in its 2006 results of operations.

DTE annually reviews the disclosure requirements of SFAS No. 115 and EITF Issue No. 03-01 and provides the required disclosure for items and amounts deemed material for disclosure

August 30, 2007
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purposes. Beginning with its 2007 Form 10-K, the Company will provide the disclosures and related information as defined in SFAS No. 115 and EITF Issue No. 03-01 for the investment activity of the securities held by the NDTs. Our disclosure will be similar to the following:

Investments in Debt and Equity Securities – Nuclear Decommissioning Trusts

We classify investments in debt and equity securities as available-for-sale and have recorded such investments at market value with unrealized gains or losses included in other comprehensive income or loss. Where a recovery mechanism from customers is in place, changes in the fair value of nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities. Our investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value.

Decommissioning

Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation, which is classified as a noncurrent liability. Based on the actual or anticipated extended life of the nuclear plant, decommissioning expenditures for Fermi 2 are expected to be incurred primarily during the period 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $x.x billion in 200x dollars and $x.x billion in 2025 dollars, using a x% inflation rate. In 2001, Detroit Edison began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be complete by 2010.

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. We believe the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission the nuclear facilities. We expect the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for these units following completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.

A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and clean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning regulatory liability.

The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary.

The following table summarizes the fair value of the nuclear decommissioning trust fund assets:

August 30, 2007
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($ in millions)	As of December 31,
	200x		200y
Fermi 2	$	xxx	$	xxx
Fermi 1	xx		xx
Low level radioactive waste	xx		xx
Total	$	xxx	$	xxx

At December 31, 200x, investments in the external nuclear decommissioning trust funds consisted of approximately xx% in publicly traded equity securities, xx% in fixed debt instruments and x% in cash equivalents. The debt securities have an average coupon rate of approximately x.x %, an average duration of approximately x.x years, and an average maturity of approximately x.x years.

The costs of securities sold are determined on the basis of specific identification. The following table sets forth the approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:

($ in millions)
Year Ended December 31,	200x	200y	200z
Realized gains	$      xxx	$      xxx	$      xxx
Realized losses	xxx	xxx	xxx
Proceeds from sales of securities	xxx	xxx	xxx

Realized gains and losses and proceeds from sales of securities for the Fermi 2 and the Low Level Radioactive Waste funds are recorded to the asset retirement obligation regulatory asset and nuclear decommissioning regulatory liability, respectively.

The following table sets forth the unrealized gains for the nuclear decommissioning trust funds:

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($ in millions)			Total
			Unrealized
	Fair Value		Gains
December 31, 200x
Equity Securities	$	xxx	$	xxx
Debt Securities		xxx		xxx
Total	$	xxx	$	xxx
December 31, 200y
Equity Securities	$	xxx	$	xxx
Debt Securities		xxx		xxx
Total	$	xxx	$	xxx

Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As Detroit Edison does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be “other than temporary” impairments.

Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $x.x million and $x.x million of unrealized losses as regulatory assets for the years ended December 31, 200x and 200y, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, impairment charges for unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. For the years ended December 31, 200x and 200y, Detroit Edison recognized impairment charges of $x.x million and $x.x million, respectively, for unrealized losses incurred by the Fermi 1 trust.

Note 14 – Financial and Other Derivative Instruments, page 115

6. Reference is made to your May 18, 2007Form 8-K which indicated that the company agreed to sell its Michigan Antrim Shale gas exploration and production properties for $l.225 billion of gross proceeds. We assume that you have discontinued cash flow hedge designation with respect to your derivative contracts used to hedge the price of nature gas. Please quantify for us the amount expected to be reclassified into earnings.

Response:

We discontinued cash flow hedge accounting for our Antrim business in the second quarter 2007 when the Antrim business was determined to be “held for sale” in accordance with SFAS No. 144 and the forecasted transactions were no longer probable of occurring. In conjunction with the Antrim sale and effective settlement of these contracts at the end of the second quarter, we

August 30, 2007
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reclassified amounts held in accumulated other comprehensive income and recorded the settlements, resulting in charges to earnings totaling $323 million ($210 million after-tax) in the second quarter of 2007.

Note 16 – Retirement Benefits and Trusted Assets, page 121

7. We note your disclosure on page 96 that you are recovering pension and other postretirement benefit expenses pursuant to calculated amounts under SFAS no. 87 and 106. Please explain to us how you are recovering pension and other postretirement benefit expenses as of your last rate case and any updates. In this regard, we note the existence of a regulatory asset of $544 million for such incurred costsprior to the adoption of SFAS no. 158 on page 96 to theForm 10-K. We also see disclosure on page 98 that indicates that the MPSC denied Detroit Edison’s request for a proposed tracking mechanism for retiree health care costs. We may have further comment.

Response:

DTE has two utilities, Detroit Edison and MichCon, which are regulated by the MPSC and apply the principles of SFAS No. 71. The MPSC has recognized pension and other post-employment benefits (“OPEB”) costs and their working capital impacts consistent with SFAS No. 87 and SFAS No. 106, respectively, in the determination of both utilities’ rates. Detroit Edison and MichCon recover pension and OPEB costs in their base rates based on actuarially justified cost projections in compliance with the requirements of SFAS No. 87 and SFAS No. 106. This recovery was most recently confirmed by the MPSC in Detroit Edison’s 2004 main electric rate case order and MichCon’s 2005 rate case order.

In addition, Detroit Edison’s 2004 main electric rate case included an MPSC-ordered dollar-for-dollar pension tracker so that designated pension revenue in base rates does not over or under recover actual pension costs and proposed a similar OPEB tracker to be determined in Detroit Edison’s next main electric rate case. Detroit Edison requested an OPEB tracker as part of an electric rate restructuring case in 2005. The MPSC denied the request for the OPEB tracker on a procedural basis, since an electric rate restructuring case is not a general rate case as instructed by the MPSC in the 2004 Order. Detroit Edison has addressed both the pension tracker and the OPEB tracker in its 2007 main electric rate case application to the MPSC.

Prior to the adoption in 2006 of SFAS No. 158, Detroit Edison had recognized a significant minimum pension liability since 2002 pursuant to SFAS No. 87. For non-regulated companies the recording of a minimum pension liability would have required an offsetting charge to other comprehensive income (“OCI”) net of taxes, which would have resulted in a significant reduction of common equity in their balance sheets. However, Detroit Edison recognized a regulatory asset instead of a charge to OCI, as such is addressed in the accounting for regulation under SFAS No. 71. This recognition was dependent upon the receipt of adequate assurance of recovery of future pension costs incurred pursuant to SFAS No. 87 from the MPSC. The

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MPSC’s historical practice in determining Detroit Edison’s rates includes the recognition of future pension costs under SFAS No. 87 and its working capital impacts. Based on this historical practice and communication received from the MPSC Staff, Detroit Edison concluded that it was probable that future pension costs as measured under SFAS No. 87 will be recognized in the revenue requirements used by the MPSC in setting Detroit Edison’s rates. Therefore, the $544 million referenced in the question is the 2005 year-end minimum pension regulatory asset balance to be recovered from customers in future years to pay for the additional minimum pension liability using actuarial studies as measured under SFAS No. 87.

Note 17 – Stock-Based Compensation, page 129

Options, page 130

8. Prospectively, please disclose the substantive conditions of your equity awards. In this regard, we did not see the vesting period disclosed for stock options. See paragraph A240.a of SFAS no. 123(R).

Response:

In addition to disclosures previously made regarding our stock-based compensation plans, in future filings, beginning with the 2007 Form 10-K, the Company will disclose the vesting periods of our equity awards. Current stock options granted vest ratably over a three-year period.

Stock Awards, page 132

9. Please advise why you are still reflecting unearned compensation as a reduction to common stock. See paragraph 74 of SFAS no. 123(R).

Response:

In adopting SFAS No. 123(R), effective January 1, 2006, the Company followed the guidance in paragraph 74, which states, in part, that “...Any unearned or deferred compensation (contra-equity accounts) related to those earlier awards shall be eliminated against the appropriate equity accounts.” Accordingly, upon adoption of SFAS No. 123(R), the Company eliminated unearned compensation related to restricted stock awards against common stock. In addition, the Company is following the guidance in paragraph A134 of SFAS No. 123(R) related to its accounting for stock awards, recognizing compensation expense and an associated increase to common stock over the vesting period of the stock awards.

The sentence “We account for stock awards as unearned compensation, which is recorded as a reduction to common stock.” was inadvertently included as part of Note 17 to the Consolidated

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Financial Statements, included in the Company’s Form 10-K for the year ended December 31, 2006. The Company will remove this sentence from its future filings.

Additionally, beginning with the Form 10-Q for the quarter ended June 30, 2007, the Company revised the caption in its Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income from “Unearned stock compensation and other” to “Stock-based compensation and other.”

Schedule II – Valuation and Qualifying Accounts, page 144

10. Please advise why Schedule II is unnecessary for the reserve associated with costs expected to be incurred in connection with planned major maintenance activities pursuant to Rule 12-09 of Regulation S-X. In this regard, we note your disclosure on page 91 that indicates you still account for the cost of the Fermi 2 refueling outages under the accrue-in-advance method.

Response:

As discussed in Note 3 of the Notes to the Consolidated Financial Statements in the 2006 Form 10-K, the Company uses the accrue-in-advance method for nuclear refueling outage costs to record a regulatory liability to match the regulatory recovery of these costs in rates set by the MPSC in accordance with SFAS No. 71, paragraph 11(b). Fermi 2, similar to other nuclear plants, shuts down every 18 months to replace nearly one-third of its reactor’s nuclear fuel and to perform maintenance work that cannot be done while the plant is operating. The MPSC has consistently allowed the pro rata recovery of outage costs over the 18-month period preceding each outage. The liability for the Fermi 2 refueling outage was $16 million and $25 million as of December 31, 2006 and 2005, respectively, and is disclosed as a regulatory liability in Note 6 of the Notes to the Consolidated Financial Statements. We acknowledge the Staff’s position, communicated in the discussions of EITF Topic No. D-88, that liabilities accrued for planned major maintenance activities should be included in Schedule II. We did not include this liability in Schedule II in the 2006 Form 10-K as we do not believe that a regulatory liability falls under the requirements of Schedule II.

* * * * *

In connection with this letter, DTE Energy Company acknowledges that:

• DTE Energy Company is responsible for the adequacy and accuracy of the disclosure in the filing

• staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

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• DTE Energy Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

We appreciate your assistance in this matter and will be pleased to provide any additional information you may need. We hope this letter responds adequately to your comments, but if you have any further questions or comments regarding this letter or our 2006 Form 10-K, please contact me at (313) 235-7134.

Very truly yours,

/s/Peter B. Oleksiak
Peter B. Oleksiak
Vice President and Controller