DTE Energy (DTE) CORRESP Correspondence with SEC

August 29, 2008

VIA ELECTRONIC TRANSMISSION (EDGAR)

H. Christopher Owings
Assistant Director
Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 3561
100 F Street, NE
Washington, D.C. 20549

Re:	DTE Energy Company Annual Report onForm 10-K for Fiscal Year Ended December 31, 2007 Filed March 7, 2008 Definitive Proxy Statement on Schedule 14A Filed April 7, 2008 File No. 001-11607
	The Detroit Edison Company Annual Report onForm 10-K for Fiscal Year Ended December 31, 2007 Filed March 17, 2008 File No. 001-02198

Dear Mr. Owings:

Set forth below are the responses of DTE Energy Company and The Detroit Edison 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 15, 2008 (the “Comment Letter”). References in this letter to “DTE” mean DTE Energy Company and its consolidated subsidiaries, references to “Detroit Edison” mean The Detroit Edison Company and its consolidated subsidiaries, and references to “we,” “us,” “our,” or the “Company” mean DTE and/or Detroit Edison, as appropriate in the context in which such terms are used. Capitalized terms used but not defined in this letter have the meanings given to such terms in our Forms 10-K for the year ended December 31, 2007.

We note that some of the SEC staff comments ask that we revise our filings. The Company has carefully considered each of the staff’s comments and does not believe that an amendment of either the DTE or the Detroit Edison 2007 Form 10-K is warranted at this time, as we do not believe the various revisions we propose to make to our disclosures in response to the staff’s comments are material in nature. Accordingly, we have not filed amended 2007 Forms 10-K and intend to implement all proposed revisions in our future filings, as described below.

August 29, 2008
Page 2

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. Where we have provided sample disclosure language for future filings, the text is marked to show changes from the language in our 2007 Forms 10-K and 2008 Proxy Statement.

DTE Energy Company

Annual Report on Form 10-K for Fiscal Year Ended December 31, 2007

General

1. In order to facilitate this review and reduce the number of comments we have not repeated comments for issues that may be applicable to the Detroit Edison Company. To the extent any comment applies to more than one registrant, please address the comment individually for each separate registrant.

Response:

The Company notes this request and has responded to the remaining DTE Form 10-K comments accordingly.

2. Please provide us with a copy of your reserve report as of December 31, 2007. Please provide this on electronic media, such as CD-ROM, if possible. If you would like this information to be returned to you, please follow the guidelines in Rule 12b-4 under the Exchange Act of 1934. See also Rule 83 under the Freedom of Information Act if you wish to request confidential treatment of that information. Please send the report to James Murphy at mail stop 7010.

Response:

A CD-ROM containing a copy of our reserve report as of December 31, 2007 has been sent today to Mr. James Murphy as requested. We note that in our cover letter to Mr. Murphy we requested that the report be treated as confidential under the Freedom of Information Act and that it be returned to us upon the completion of his review.

3. Please provide added oil and gas disclosure as contemplated under SFAS 69, such as a year to year reserve changes table and other such disclosures. Please see paragraphs seven through thirty of SFAS 69.

August 29, 2008
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Response:

SFAS No. 69 was issued to address the view by the SEC and the FASB that additional oil and gas disclosures were needed to provide information on the financial position and operating results of oil and gas producing enterprises. In accordance with SFAS No. 69, the significance of oil and gas activities is assessed by comparing revenue, results of operations and assets of oil and gas activities to the total company. SFAS No. 69, paragraphs 7 and 8, state the following:

7. In addition, publicly traded enterprises that have significant oil and gas producing activities shall disclose with complete sets of annual financial statements the information required by paragraphs 10-34 of this Statement. Those disclosures relate to the following and are considered to be supplementary information:

a.	Proved oil and gas reserve quantities
b.	Capitalized costs relating to oil and gas producing activities
c.	Costs incurred for property acquisition, exploration, and development activities
d.	Results of operations for oil and gas producing activities
e.	A standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities.

8. For purposes of this Statement, an enterprise is regarded as having significant oil and gas producing activities if it satisfies one or more of the following tests. The tests shall be applied separately for each year for which a complete set of annual financial statements is presented.

a.	Revenues from oil and gas producing activities, as defined in paragraph 25 (including both sales to unaffiliated customers and sales or transfers to the enterprise’s other operations), are 10 percent or more of the combined revenues (sales to unaffiliated customers and sales or transfers to the enterprise’s other operations) of all of the enterprise’s industry segments.
b.	Results of operations for oil and gas producing activities, excluding the effects of income taxes, are 10 percent or more of the greater of:

(1)	The combined operating profit of all industry segments that did not incur an operating loss
(2)	The combined operating loss of all industry segments that did incur an operating loss.

c. The identifiable assets of oil and gas producing activities (tangible and intangible enterprise assets that are used by oil and gas producing activities, including an allocated portion of assets used jointly with other operations) are 10 percent or more of the assets of the enterprise, excluding assets used exclusively for general corporate purposes.

DTE’s principal business is the operation of regulated electric and gas utilities. DTE also engages in oil and gas activities through its Unconventional Gas Production (“UGP”) business unit. Prior to June 2007, the UGP business unit conducted natural gas exploration, development and production in the Antrim (Michigan) and Barnett (Texas) shale areas. The Antrim shale, located in northern Michigan, is a mature area with stable production volumes. The Barnett shale, located in the Fort Worth, Texas area, is commonly viewed as three areas in varying stages of development: the Core, Western and Southern areas. The Core area is the most developed area. The Western acreage, while not as mature as the Core, is the focus of much of the Company’s new exploration and development in the Barnett shale. The Southern area has also been an area of interest for future development, but in general, production has not yet proved to

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be economical. In June 2007, DTE sold its Antrim shale business and in January 2008, the Barnett shale Core properties were sold, which together represented a significant portion of the UGP business. The Company has also stated its intention to monetize some or all of its remaining oil and gas producing activities (i.e.,Barnett Western), but a definitive timetable for additional monetizations has not been set at this time.

DTE has performed the following analysis to assess the significance of potential disclosures pursuant to SFAS No. 69.

As of and for the year ended December 31, 2007
($ in millions)	Operating			Income before Income
	Revenues			Tax and Minority Interest			Assets
Unconventional Gas Production	$	95		$	16		$	355
Total DTE, Continuing Operations		8,829			605			22,980
UGP, % of Total DTE		1.1	%		2.6	%		1.5%
As of and for the year ended December 31, 2006
($ in millions)	Operating			Income before Income
	Revenues			Tax and Minority Interest			Assets
Unconventional Gas Production	$	99		$	14		$	611
Total DTE, Continuing Operations		8,159			536			23,100
UGP, % of Total DTE		1.2	%		2.6	%		2.6%
As of and for the year ended December 31, 2005
($ in millions)	Operating			Income before Income
	Revenues			Tax and Minority Interest			Assets
Unconventional Gas Production	$	74		$	5		$	434
Total DTE, Continuing Operations		8,094			415			22,255
UGP, % of Total DTE		0.9	%		1.2	%		2.0%

Based on the above analysis, DTE’s oil and gas producing activities did not exceed the SFAS No. 69 thresholds and are not considered significant for 2007, 2006 or 2005.

The SFAS No. 69 analysis above includes revenues, pre-tax results of operations and assets for UGP ongoing oil and gas producing activities and excludes non-recurring items arising from the monetization of a portion of DTE’s oil and gas holdings. The SFAS No. 69 disclosures focus on oil and gasproducingactivities, and as illustrated in Example 3 of Appendix A of SFAS No. 69, the disclosures are intended to focus on results of operations for producing activities, excluding items that are not part of producing activities. The Company believes that gains/losses resulting from a decision to exit the business should not be contemplated when assessing the significance

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of oil and gas producing activities. A reconciliation of the SFAS No. 69 test information to Note 19 – Segment and Related Information in DTE’s 2007 Form 10-K is as follows.

Reconciliation of SFAS 131 Reported Segment information to SFAS 69 disclosure tests
For the year ended December 31, 2007
(in millions)
	UGP			Total DTE
	Continuing Operations			Continuing Operations
Operating Revenues - SFAS 131 disclosures	$	(228	)	$	8,506
Adjustments:
Losses recognized on discontinuance of cash flow hedging		323			323
Operating Revenues - SFAS 69 disclosure tests	$	95		$	8,829
Net income (loss) - SFAS 131 disclosures	$	(217	)	$	787
Adjustments:
Income tax expense (benefit)		(117	)		364
Minority interest					4
Gain on sale of Antrim business					(900	)
Losses recognized on discontinuance of cash flow hedging		323			323
Impairment loss - Barnett Southern acreage		27			27
Income before Income Taxes and Minority Interest - SFAS 69 disclosure tests	$	16		$	605
Reconciliation of SFAS 131 Reported Segment information to SFAS 69 disclosure tests
For the year ended December 31, 2006
(in millions)
	UGP			Total DTE
	Continuing Operations			Continuing Operations
Operating Revenues - SFAS 131 disclosures	$	99		$	8,159
Adjustments:
None
Operating Revenues - SFAS 69 disclosure tests	$	99		$	8,159
Net income (loss) - SFAS 131 disclosures	$	9		$	389
Adjustments:
Income tax expense		5			146
Minority Interest					1
Income before Income Taxes and Minority Interest - SFAS 69 disclosure tests	$	14		$	536

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Reconciliation of SFAS 131 Reported Segment information to SFAS 69 disclosure tests
For the year ended December 31, 2005
(in millions)
	UGP		Total DTE
	Continuing Operations		Continuing Operations
Operating Revenues - SFAS 131 disclosures	$	74	$	8,094
Adjustments:
None
Operating Revenues - SFAS 69 disclosure tests	$	74	$	8,094
Net income (loss) - SFAS 131 disclosures	$	4	$	272
Adjustments:
Income tax expense		1		106
Minority interest				37
Income before Income Taxes and Minority Interest - SFAS 69 disclosure tests	$	5	$	415

In the fall of 2006, DTE announced its intention to explore a multi-year strategy for the monetization or sale of certain of its non-regulated businesses, including its UGP properties. In June 2007, DTE sold its Antrim shale gas exploration and production business through a sale of all of the capital stock of DTE Gas & Oil Company (“DGO-Antrim”). The pre-tax gain recognized on the sale amounted to $900 million ($580 million after-tax).

The Company had previously entered into forward contracts to hedge a substantial portion of the Company’s price risk related to expected gas production from the DGO-Antrim business through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income (“OCI”). Although the Company retained these financial contracts, upon the sale of DGO-Antrim the contracts no longer qualified as cash flow hedges, as the Company no longer controlled the gas production from DGO-Antrim. In conjunction with the DGO-Antrim sale, DTE reclassified amounts held in OCI reducing its operating revenues and pre-tax earnings in 2007 by $323 million (after-tax impact of $210 million).

In addition, a pre-tax impairment loss of $27 million was recorded in 2007 related to the write-off of costs related to DTE’s properties held in the Southern area of the Barnett shale. As part of its monetization activities, during 2007 the Company attempted to sell the Southern and Core areas of its Barnett shale properties, as its intention is to focus its development efforts on the Western acreage. The sale of the Core properties was completed on January 15, 2008, but potential buyers expressed no interest in the Southern area. As the Company was unable to monetize the Southern area, it ceased development activity in this area and recorded an impairment of the assets in 2007.

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The gain on sale of DGO-Antrim and related loss from cash flow hedging and the Barnett Southern acreage impairment items occurred as a result of DTE’s monetization activities, and are non-recurring events that result from the Company’s decision to exit these activities. Company management concluded that such events resulting from the exit of oil and gas producing activities should be excluded for purposes of evaluating the significance of ongoing oil and gas producing activities to DTE’s consolidated operations pursuant to SFAS No. 69.

The following additional factors were considered in the determination that the SFAS No. 69 supplemental oil and gas disclosures were not material or meaningful to the consolidated financial statements of DTE:

• We also gave consideration to an alternative method of performing the SFAS No. 69 significance tests which included the impacts of the monetization activities as part of oil and gas producing activities. By including the gains and losses resulting from actions to exit the businesses as described above, the SFAS No. 69, paragraph 8(b), 10% threshold for results of operations would have been exceeded for 2007, but the results would have been substantially below the threshold for 2006 and 2005. The results of the threshold test for operating revenues and assets would have been substantially below the 10% threshold for all years. The UGP activities which have been sold are no longer included in the year-end reserves, capitalized costs and future net cash flows. Accordingly, the supplemental disclosures would not be meaningful in relation to the non-recurring gains/losses upon exit of the businesses that caused the 2007 results of operations disclosure threshold to be exceeded.

• Management believes that the supplemental disclosures specified by SFAS No. 69 are intended to provide the users of financial statements with information about proved reserves in order to understand historical activity in order to assess potential future operating results and cash flows. However, due to the sale of DGO-Antrim in 2007 and the sale of Barnett Core reserves in early January 2008 (proceeds from this sale are disclosed in the 2007 financial statements as a subsequent event), the financial impacts of the DGO-Antrim and Barnett Core reserves are clearly known. As such, disclosure of activity for these sold reserves is not meaningful for financial statement users, and the remaining oil and gas producing activities (Barnett Western) are clearly insignificant to DTE under the SFAS No. 69 criteria. The following table summarizes the proved reserves by area.

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Proved reserves (Bcfe)	As of December 31,
	2007		2006		2005
DGO-Antrim shale (sold June 2007)		-		442		338
Barnett shale
Core (sold January 2008)		75		60		11
Western		144		111		48
Southern (impaired 2007)		0		3		-
Total		219		616		397

	As detailed in the table above, of the 616 Bcfe of proved reserves at December 31, 2006, all but the Barnett Western area had been monetized (sold, pending sale or impaired following attempted sale) by December 31, 2007. The proved reserves in the Barnett Western area were only 18% of the total proved reserves at December 31, 2006.
•	Excluding the impacts of the monetization transactions, the Company’s oil and gas producing activities have not been significant historically. Similarly, UGP projections indicate that oil and gas producing activities are not expected to be significant prospectively. With the DGO-Antrim sale in 2007 and the sale of Barnett Core properties in 2008, a substantial majority of the mature producing wells have been sold. In 2007 through January 2008, DTE has sold approximately 82% of the total reserves it owned as of December 31, 2006. Due to these sales and management’s refocused strategy, DTE’s oil and gas producing activities are expected to be even less significant in the future. At the time of the filing of DTE’s 2007 Form 10-K, DTE anticipated 2008 income before income taxes for the UGP segment to be in the range of $3-5 million, compared to 2007 income before income taxes of $16 million. (Income before income taxes referenced excludes significant non-recurring events.) Anticipated UGP income before income taxes is less than 2% of estimated 2008 consolidated income before income taxes, further emphasizing the insignificance of the oil and gas producing activities to the consolidated financial statements. DTE also anticipates lower estimated capital expenditures for oil and gas producing activities in 2008 of approximately $100 million, compared to 2007 capital expenditures of approximately $140 million. Because the ongoing oil and gas producing activities are not significant to DTE, the supplemental disclosures would not provide information that is material or meaningful for users of the financial statements.
•	Consistent with prior years, DTE includes information on proved reserves, producing wells, acreage, developed and undeveloped leases, results of operations, capital expenditures and future undiscounted net cash flows in Item 1, Business and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) of DTE’s Form 10-K. The Company includes this information in the Business section and MD&A as part of its discussion of its operating segments to assist the users of the financial statements to understand the drivers of business activities and results of operations for each operating

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segment, including UGP. Although this information is believed to be useful for understanding and analysis of the operating segment, it is supplemental disclosure not required by SFAS No. 69 for purposes of the Company’s consolidated financial statements. Proceeds from the sale of DGO-Antrim in 2007 and the Barnett Core properties in 2008 are also disclosed in MD&A and the Notes to Consolidated Financial Statements.

•

Lastly, it would be impracticable for DTE to provide the portion of the supplemental disclosures related to the DGO-Antrim oil and gas activities, which comprised a significant portion of DTE’s total oil and gas activities in 2007. Historically, DTE has not presented this information as its oil and gas activities did not meet the significance test of SFAS No. 69 and therefore we did not gather and retain all of the underlying DGO-Antrim-related data that would be needed for a 2007 disclosure. Since DTE sold DGO-Antrim mid-year 2007, the associated data was transferred to the new owners of DGO-Antrim and therefore is not readily available to DTE. The Company believes that the effort and cost involved in attempting to gather and compile the necessary information are not warranted as the disclosures are not material or meaningful, as described above.

2008 and 2009 Monetization Activity in the UGP segment

As discussed above, in late 2007, DTE agreed to sell gas properties located in the Core region of the Barnett shale. The transaction closed in January 2008 and an after-tax gain of $81 million was recognized. This transaction was a continuation of the monetization activities initiated in 2007. The Company may also sell additional Barnett shale gas properties in late 2008 or in 2009. Consistent with our 2007 analysis, the gain on sale of the Barnett Core properties and gains/losses on any future monetization activity will be excluded from our 2008 and future SFAS No. 69 significance analyses and we expect that the remaining oil and gas producing activities will continue to be substantially below the SFAS No. 69 threshold. Excluding the gain on the 2008 sales, UGP income before income taxes is expected to be approximately 2% of 2008 consolidated income before income taxes.

Part II

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

Capital Resources and Liquidity, page 52

Contractual Obligations, page 56

4. Please advise and revise to clarify whether your table of contractual obligations includes other long term liabilities reflected on balance sheet of $303 million. Also, please include a footnote to the table discussing your planned funding of pension and post retirement benefit plans if material. Refer to Item 303 (a) (5) of Regulation S-K.

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Response:

The table of contractual obligations does not include other long-term liabilities reflected on the balance sheet of $303 million. The other long-term liability balance at December 31, 2007 consists primarily of accruals for injuries and damages, environmental remediation and miscellaneous other long-term liabilities and are not directly derived from contracts or other agreements and therefore have been excluded from the contractual obligations table.

In future filings, beginning with the 2008 Form 10-K, the Company will include a footnote to the line item in the table “Other long-term obligations” as follows:

Excludes other long-term liabilities of $XXX million not directly derived from contracts or other agreements.

The Company disclosed its planned funding of pension and post retirement plans in its Critical Accounting Estimates section of MD&A as follows:

Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made a $180 million pension contribution in 2006 and made a $150 million pension contribution in 2007. At the discretion of management and depending upon financial market conditions, we anticipate making up to a $150 million contribution to our qualified pension plans in 2008 and up to $400 million over the next five years. Also, we anticipate making up to a $5 million contribution to our nonqualified benefit plans in 2008 and up to $25 million over the next five years. We made a $116 million contribution to our postretirement benefit plans in 2006 and made a $76 million contribution to our postretirement benefit plans in 2007. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $116 million contribution to our postretirement plans in 2008 and up to $600 million over the next five years.

Planned funding levels are also disclosed in Note 17 of the Notes to Consolidated Financial Statements.

In future filings, beginning with the 2008 Form 10-K, the Company will also include a footnote to the table of contractual obligations indicating the status of minimum pension funding levels and planned funding of pension and post retirement benefit plans as follows:

At December 31, 200x, we had met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our nonqualified benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are also disclosed in the Critical Accounting Estimates section of MD&A and in Note X of the Notes to Consolidated Financial Statements.

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Critical Accounting Estimates, page 57

5. We noted on page 30 to your annual report that you incurred significant revisions to your valuation estimates with regard to the Company’s long-dated portion of energy contracts, and you recorded $30 million of unrealized losses, which represented approximately 4% of income from continuing operations. Please revise the future critical accounting policy disclosure to provide an overview of how fair value is calculated, the specific numerical inputs used, and a comprehensive sensitivity analysis which allows the reader to estimate possible future impacts to net income. For additional guidance, refer to Item 303 of Regulation S-K as well as section five of the Commission’s Interpretive Release on Management’s Discussion and Analysis of Financial Condition and Results of Operation which is located on our website at: http://www.sec.gov/rules/interp/33-8350.htm.

Response:

An overview of how fair value is calculated including the types of inputs utilized has been historically provided in the Fair Value section of MD&A. Additionally, Item 7A, Quantitative and Qualitative Disclosures About Market Risk presents quantitative and qualitative disclosure about market risk which includes a sensitivity analysis of a 10% change in commodity prices which is the most significant driver of changes in value for our energy contracts. In connection with our implementation of SFAS No. 157, DTE’s 2008 Forms 10-Q have included further discussion of the definition of fair value and related inputs.

In future filings, beginning with the DTE 2008 Form 10-K, DTE will aggregate and summarize such information for inclusion in the Critical Accounting Estimate section. Additionally, to further enhance sensitivity disclosures, DTE will include the Company’s sensitivity to discount rates. As the most significant driver of earnings volatility is attributable to commodity price movements, historically presented sensitivities are considered adequate.

An example of the proposed addition to the Critical Accounting Estimate disclosure is presented below:

Risk Management and Trading Activities

Risk management and trading activities are accounted for in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,as amended and interpreted. As amended, SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives are recorded at fair value and shown as “Assets or liabilities from risk management and trading activities” in the Consolidated Statements of Financial Position. Derivatives are measured at fair value, and changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. A

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majority of thecommodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair values of derivative contracts are determined from a combination of active quotes, published indexes and mathematical valuation models.We generally derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods in which external market data is not readily observable, we estimate value using mathematical valuation models. Valuation models require various inputs and assumptions, including forward prices, volatility, interest rates, and exercise periods.For those inputs which are not observable we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes, current market transactions or other observable market information may permit us to record gains at inception of new derivative contracts.

The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. The cash returns we actually realize on our derivatives may be different from the results we estimate using models.As fair value calculations are estimates based largely on commodity prices, we perform sensitivity analysis on the fair values of our forward contracts. See sensitivity analysis in the Fair Value section of MD&A.

Item 8. Financial Statements and Supplementary Data, page 69

Controls and Procedures, page 70

6. Please confirm, if true, that your controls and procedures were designed at the reasonable assurance level and that your principal executive officer and principal financial officer concluded that your disclosure controls and procedures are effective at the reasonable assurance level. If so, please revise your disclosure accordingly in future filings. In the alternative, remove the reference to the level of assurance of your disclosure controls and procedures included in your current disclosure. Please refer to SEC Release No. 34-55929.

Response:

The Company confirms that its disclosure controls and procedures were designed at the reasonable assurance level and its principal executive officer and principal financial officer concluded that its disclosure controls and procedures were effective at the reasonable assurance level. The Company revised its disclosure in its 2008 Second Quarter Forms 10-Q to make clear that its disclosure controls and procedures were designed to provide reasonable assurance as

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requested by the Staff. Consistent with that disclosure, beginning with the 2008 Third Quarter Forms 10-Q, the revised disclosure will be as follows:

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of Xxxxxxx xx, 200x, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuringproviding reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensureprovide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

Note 1 – Significant Accounting Policies, page 79

7. Please revise future disclosure to include the amounts of unbilled revenues.

Response:

In future filings, beginning with the 2008 Forms 10-K for DTE and Detroit Edison, the Company will add the following disclosure of the amounts of unbilled revenue to Note 1 – Significant Accounting Policies – Revenues:

Total unbilled revenues at December 31, 200x and 200x were $XXX million and $XXX million, respectively.

Note 5 – Regulatory Matters, page 93

8. Please explain to us and revise your disclosure to indicate which regulatory assets are not earning a return. If they are not earning a return revise your disclosure to provide the amounts and recovery periods of regulatory assets not earning a current return. See paragraph 20 of SFAS no. 71.

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Response:

In future filings, beginning with the 2008 Form 10-K, the Company will clarify its disclosure of the amounts and recovery periods of regulatory assets not earning a current return. A draft of the portion of Note 5 – Regulatory Matters – Regulatory Assets and Liabilities reflecting this clarification follows:

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in Detroit Edison or MichCon’s rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

ASSETS

*     *     *     *     *

Regulatory assets not earning a return:

•     Deferred environmental costs— The MPSC approved the deferral and recovery of investigation and remediation costs associated with Gas Utility’s former MGP sites. This asset is offset in working capital by an environmental liability reserve. The amortization of the regulatory asset is not included in MichCon’s current rates because it is offset by the recognition of insurance proceeds. MichCon will request recovery of the remaining asset balance in future rate filings after the recognition of insurance proceeds is complete.

•     Recoverable pension and postretirement costs—In 2007, the Company adopted SFAS No. 158 which required, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. The Company received approval from the MPSC to record the charge related to the additional liability as a regulatory asset since Tthe traditional rate setting process allows for the recovery of pension and postretirement costs as measured by generally accepted accounting principles. The asset will reverse as the deferred items are recognized as benefit expense in net income.

•     Asset retirement obligation— Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 and FIN 47. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant.

•     Other recoverable income taxes— Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates. This asset will reverse over the remaining life of the related plant.

•     Deferred income taxes — Michigan Business Tax (MBT)— In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the

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deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense.

Definitive Proxy on Schedule 14A

Executive Compensation, page 25

Compensation Discussion and Analysis, page 25

Philosophy and Objectives, page 25

9. We note that individual officer performance is an important factor in determining compensation. You indicate on page 31 that the annual incentive plan awards are adjusted by an individual performance modifier. In future filings, please discuss how the specific forms of compensation are structured and implemented to reflect each named executive officer’s individual performance and/or individual contribution to these items of the registrant’s performance, describing the elements of individual performance and/or contribution that are taken into account. See Item 402(b)(2)(vii) of Regulation S-K.

Response:

As discussed in our response to Comment 11, we target total compensation to provide for market-competitive compensation, which is adjusted based on Company performance and the performance of individual Named Executive Officers. The annual cash bonus compensation for each Named Executive Officer is tied to corporate objectives, business unit objectives and individual performance. At the beginning of each year, the Organization and Compensation Committee assesses the overall performance of the Chief Executive Officer for the prior year. The Chief Executive Officer assesses the performance of the other Named Executive Officers for the prior year and recommends individual performance modifiers (expressed as a percentage multiplier) to the Organization and Compensation Committee for their modification and approval. The individual performance modifier adjusts a Named Executive Officer’s annual cash bonus such that the Named Executive Officer’s actual cash bonus ranges between zero and 150% of the pre-adjusted calculated award, based on the Organization and Compensation Committee’s evaluation of individual accomplishments and contributions.

For 2007, the individual performance evaluations of the Named Executive Officers were conducted on a subjective basis without specific weighting of any particular factor. After adjusting for individual performance, annual incentive awards for the Named Executive Officers ranged from 110% to 125% of the awards calculated on the basis of Company performance and the measures achieved. The methodology for determining the calculated awards is described on page 31 of the 2008 Proxy Statement. At the beginning of 2008, the Organization and Compensation Committee approved a list of qualitative factors that will be used in determining the 2008 individual performance modifier for each Named Executive Officer. These pre-

August 29, 2008
Page 16

determined performance criteria will provide for a more focused evaluation of each Named Executive Officer’s 2008 individual performance modifier.

Although at this time it is not possible to provide the disclosure for future proxy statements since evaluations have not yet been made and the performance criteria may change from year to year, the following language is illustrative of the type of disclosure that may be included, when applicable, in the appropriate section of the Compensation Discussion and Analysis in future proxy statements, beginning with the 2009 Proxy Statement:

Calculated awards are adjusted by an individual performance modifier for each of the Named Executive Officers. Individual performance criteria are set at the beginning of each calendar year for each of the Named Executive Officers. For 200x, qualitative criteria include, as applicable, leadership performance, overall operational and customer performance, continuous operational improvements and [other appropriate operating measures]. The Organization and Compensation Committee evaluates the individual performance of each of the Named Executive Officers and approves an adjustment to the annual award based on the individual contribution and performance. The individual performance modifier adjusts a Named Executive Officer’s annual cash bonus such that the Named Executive Officer’s actual cash bonus ranges between zero and 150% of the pre-adjusted calculated award. In 200x, after adjusting for individual performance, annual incentive awards for the Named Executive Officers ranged from xxx% to xxx% of the calculated awards.

Annual and Long-Term Incentive Plans, page 29

10. We note that you have not provided a quantitative discussion of the specific terms of the annual goals to be achieved for your named executive officers to earn their annual cash awards and long-term incentives in 2007. In future filings, please disclose or, to the extent you believe disclosure of these financial and operational goals is not required because it could result in competitive harm, provide us on a supplemental basis a detailed explanation for this conclusion.

See instruction 4 to Item 402(b). If disclosure of these goals would cause competitive harm, please discuss further how difficult it will be for the named executive officer or how likely it will be for you to achieve the performance objectives or other factors. See Item 402 (b)(2)(v) of Regulation S-K and Question 118.04 of Compliance & Disclosure Interpretations on Regulation S-K athttp://www.sec.gov/divisions/corpfin/guidance/regs-kinterp.htm. Further, please discuss any discretion that may be exercised in granting these awards absent attainment of the stated performance goals.

Response:

In future filings, beginning with the 2009 Proxy Statement, the Company will expand and supplement its disclosure in the Compensation Discussion and Analysis to detail the goals and final results for the financial performance measures which are material to the calculation of the Named Executive Officers’ incentive payments, unless the Company believes that disclosure of incentive plan financial goals will cause competitive harm, in which case the Company will

August 29, 2008
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provide to the SEC at that time on a supplemental basis a detailed explanation for its conclusion. The following is illustrative of the type of disclosure the Company will include in future filings (using the approved 2008 performance measures by way of example):

Annual Incentive Plan
Performance Measures	Weight
DTE Energy EPS	x%
DTE Energy Cash Flow	x%
Customer Satisfaction Rating – Percentile Improvement	x%
MPSC Complaints	x%
Safety	x%
Diversity Hiring – Minority	x%
Diversity Hiring – Female	x%

The DTE Energy EPS target was $x.xx, and the actual result for 200x was $x.xx, resulting in a payout of xxx% of the target amount for that objective. The DTE Energy cash flow target was $xxx million, and the actual result for 200x was $xxx million, resulting in a payout of xxx% of the target amount for that objective.

*     *     *     *     *

Long-Term Incentive Plan (200x Payout of Awards Granted in 200x)
Measure	Weight
Total Shareholder Return vs. S&P Electric Utility Index	x%
Balance Sheet Health	x%
Employee Engagement	x%

Thetotal shareholder return compared to the S&P Electric Utility Index target was xx percentile, and the actual result for 200x was xx percentile, resulting in a payout levelof xx.xx%, as certified by the O&C Committee, was xx.xx%.

The amounts paid under the plans will be disclosed and properly footnoted in the Summary Compensation Table.

Summary Compensation Table, page 35

11. We refer you to Release 33-8732A, Section II.B.1. The Compensation Discussion and Analysis should be sufficiently precise to identify material differences in compensation policies with respect to individual executive officers. In future filings, please explain the reasons for the differences in the amounts of compensation awarded to the named executive officers. For example, Mr. Earley received salary, awards and non-equity incentive plan compensation that were significantly higher than the amount received by the other named executive officers. We direct your attention to Item 402(b)(2)(vii) of Regulation S-K.

August 29, 2008
Page 18

Response:

As described on page 28 of the Company’s 2008 Proxy Statement, the structure of the compensation and benefits program is applied consistently to the Named Executive Officers, including the Chief Executive Officer. There are no material differences in the compensation policies applied to the Chief Executive Officer as compared to the other 2007 Named Executive Officers.

On an annual basis, the Organization and Compensation Committee of the Board of Directors reviews and analyzes the responsibilities of each of the Named Executive Officers, including the Chief Executive Officer, and on that basis proposes an appropriate level of compensation for each of the Named Executive Officers. Each component of each Named Executive Officer’s proposed compensation is then compared, measured and evaluated against a peer group of companies, as described on page 27 of the 2008 Proxy Statement. On pages 27-28 of the 2008 Proxy Statement, we discussed the sources of our benchmarking data that is used by the Organization and Compensation Committee for this purpose. On page 29 we discussed market reference points and that they “target the median for most positions, adjusted to take into account differences in company size within the peer group.” Also on page 29 we explained that “the current mix among base salary, the Annual Incentive Plan and the Long-Term Incentive Plan is appropriately set to provide market-competitive compensation when Company performance warrants.”

In future filings, beginning with the 2009 Proxy Statement, we will add the following statement to an appropriate section of the Compensation Discussion and Analysis:

Differences in compensation between the Chief Executive Officer and the other Named Executive Officers are due, in part, to an analysis of peer group benchmark data, as well as differences in the responsibilities of each Named Executive Officer. We review each element of total compensation, both individually and on a combined basis, for each Named Executive Officer and make adjustments as appropriate based on these comparisons.

The Detroit Edison Company

Annual Report on Form 10-K for Fiscal Year Ended December 31, 2007

Item 7A. Quantitative and Qualitative Disclosures about Market Risk, page 15

12. You indicate that you have commodity price risk. Please explain to us what earnings risk, if any, you may have as a regulated utility with regard to commodity price risk instruments. We assume the Company has cash flow risk with regard to such contracts. In this regard, enhance your disclosure to specifically address the terms, for example the length of the commodity contracts in place, and the rate making mechanics in place that mitigate or reduce your liquidity risk. Prospectively, please enhance your disclosure by choosing one of the three methods required by Item 305 of Regulation S-K.

August 29, 2008
Page 19

Response:

The economic impact (on the shareholder) of commodity price exposure for Detroit Edison is negligible. Gains or losses upon settlement of said contracts executed by Detroit Edison are refunded to/recovered from its customers, primarily via the PSCR mechanism and a tracking mechanism to mitigate losses from customer migration due to the electric Customer Choice program. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery. Detroit Edison manages this risk through timely regulatory filings, interim rate relief proceedings, tracking mechanisms and long-term supply contracts.

Our current disclosure as modified for proposed prospective changes is presented below:

Commodity Price Risk

We have commodity price risk arising from market price fluctuations. We have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, and electricityand base metals to meet our service obligations. Further, changes in the price of electricity can impact the level of exposure of the electric Customer Choice program and uncollectible expenses. To limit our exposure to commodity price fluctuations, we have applied various approaches including forward energy, capacity, storage and futures contracts, as well asHowever, the Company does not bear significant exposure to earnings risk as such changes are included in regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of the PSCR mechanism (see Note 1 of the Notes to Consolidated Financial Statements) and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs.The Company is exposed to short term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery. DTE manages this risk through annual regulatory filings, interim rate relief proceedings, tracking mechanisms and long-term supply contracts.

Consolidated Statements of Financial Position, page 23

13. Please explain to us what comprises other current liabilities of $243 million and $288 million as of December 31, 2007 and 2006, respectively. Please state separately, in the balance sheet or in a note thereto, any item in excess of 5 percent of total current liabilities. Please refer to Rule 5-02 of Regulation S-X.

Response:

No items included in Other Current Liabilities are in excess of five percent of Total Current Liabilities and therefore are not required to be stated separately in the balance sheet or in a note thereto.

Other Current Liabilities amounts include PSCR over/under recovery, deferred income taxes, accrued employee payroll and incentive expenses and various other accruals.

August 29, 2008
Page 20

The Company also notes that it performed a similar analysis with respect to DTE and reconfirms that all items in excess of five percent of Total Current Liabilities had been stated separately on the face of the balance sheet and that no additional items included in Other Current Liabilities exceeded the five percent threshold.

Note 1 – Significant Accounting Policies, page 26

Net Property, Plant and Equipment, page 27

14. We note your disclosure, “we credit depreciation, depletion and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures.” In this regard, we assume you are removing the incurred cost from PP&E because a separate recovery mechanism appears to be in place as discussed on page 35 to yourForm 10-K, and you have recorded an offsetting equal amount to expense to reduce PP&E. If our assumption is not correct, then please explain.

Response:

In 2000, the Michigan Legislature enacted Public Act 141 which allowed Detroit Edison to defer, among other items, costs associated with environmental capital, including depreciation and the related financing costs. The deferred recovery of stranded costs associated with the fixed cost component of Detroit Edison’s generation capital for customers moving to the electric Customer Choice program was also allowed.

The environmental and generation capital expenditures had been capitalized as part of PP&E when the assets were placed into service. At that time, the environmental capital expenditures were not part of rate base and therefore the Michigan Public Service Commission (“MPSC”) allowed Detroit Edison to establish a regulatory asset for depreciation (recovery of) and financing costs (return on) related to the environmental expenditures and also ordered a surcharge be implemented to enable recovery of these costs. As the capitalized environmental costs were depreciated, the regulatory asset related to future recovery through the surcharge was recorded, with an offsetting credit to depreciation.

Generation capital costs were included in rate base and revenue requirements were established to enable recovery of and return on these capital costs as part of the ratemaking process. As a result of the establishment of the electric Customer Choice program in 2000 and the resultant loss of customers, in certain periods, Detroit Edison suffered a revenue deficiency which created stranded costs related to its generation capital. The stranded costs represented depreciation (recovery of) and financing costs (return on) associated with Detroit Edison’s generation fleet. The MPSC allowed Detroit Edison to establish a regulatory asset for the stranded costs and also ordered a surcharge be implemented to enable recovery of these costs. As the capitalized generation costs were depreciated, the regulatory asset related to future recovery through the surcharge was recorded, with an offsetting credit to depreciation.

August 29, 2008
Page 21

At December 31, 2007, the regulatory assets related to deferred environmental expenditures are nearly fully amortized and stranded costs are fully amortized. From time to time, deferral of other plant-related costs is ordered as part of the regulatory process. Therefore in future filings, beginning with the 2008 Form 10-K, we will update the portion of Note 1, Significant Accounting Policies, referenced in your question as follows:

We credit depreciation, depletion and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expendituresplant-related costs such as depreciation or plant-related financing costs. We charge depreciation, depletion and amortization expense when we amortize these regulatory assets. We credit interest expense to reflect the accretion income on certain regulatory assets.

Commitments and Contingencies, page 50

15. We have read your disclosure regarding the contaminated MGP sites. Please explain to us when the cost studies were conducted in 2007. Based on the amount accrued in your September 30, 2007Form 10-Q, it appears you accrued an additional $4 million in the last quarter of 2007 related to the MGP sites. In this regard, please explain how you evaluate and accrue environmental liabilities under SOP no. 96-1 and SFAS no. 5. Furthermore, please explain to us if the MGP site remediation costs are being recovered in rates. Lastly, please explain to us your policy for capitalizing costs. In this regard, we note that you intend on capitalizing $6 million of costs related to the ash landfill in 2008.

Response:

During the fourth quarter of each year, including 2007, detailed projections of costs to be incurred are developed for any environmental issues that require remediation. These projected costs cover the entire life cycle of the site, which may span periods in excess of ten years. This process uses a zero based budgeting methodology which reexamines each assumption and line item in the forecast. These projections then become the basis for the year end financial statement accrual for the environmental remediation liability in accordance with SOP No. 96-1 and SFAS No. 5.

During interim periods, the Company reviews the progress of ongoing remediation projects and adjusts previously recorded reserves as conditions warrant. As work such as excavation and other remediation activities progresses on the various sites, additional information may be obtained that could result in an adjustment to the estimated liability.

Direct costs for the purchase or construction of fixed assets that are deemed to benefit future periods are classified as capital costs and accordingly are excluded from the recorded liability. Examples of such costs contemplated in the planned 2008 capital expenditures include the construction of a storm water detention pond, pump house, and slurry wall.

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Page 22

Environmental remediation costs incurred, including MGP site remediation costs, are included in Detroit Edison’s general rate case filings and are considered, along with all other costs, in determining Detroit Edison’s revenue requirement.

*  *  *  *  *

In connection with this letter, the Company acknowledges that:

• the Company is responsible for the adequacy and accuracy of the disclosure in the filings;

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

• the 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 2007 Forms 10-K or 2008 Proxy Statement, please contact me at (313) 235-7134.

Very truly yours,

/s/ Peter B. Oleksiak

Peter B. Oleksiak
Vice President and Controller