UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended March 31, 2008

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Michigan (State or other jurisdiction of incorporation or organization)		38-3217752 (I.R.S. Employer Identification No.)
2000 2nd Avenue, Detroit, Michigan (Address of principal executive offices)		48226-1279 (Zip Code)

313-235-4000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer   o (Do not check if a smaller reporting company)		Smaller Reporting Company o

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

Yes o No þ

At March 31, 2008, 163,148,592 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.

 

 

DTE Energy Company
Quarterly Report on Form 10-Q
Quarter Ended March 31, 2008

TABLE OF CONTENTS

						Page
Definitions							1
Forward-Looking Statements							2
Part I – Financial Information
		Item 1.		Financial Statements
				Consolidated Statements of Operations (Unaudited)			27
				Consolidated Statements of Financial Position (Unaudited)			28
				Consolidated Statements of Cash Flows (Unaudited)			30
				Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Unaudited)			31
				Notes to Consolidated Financial Statements (Unaudited)			32
		Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			3
		Item 3.		Quantitative and Qualitative Disclosures About Market Risk			24
		Item 4.		Controls and Procedures			26
Part II – Other Information
		Item 1.		Legal Proceedings			52
		Item 1A.		Risk Factors			52
		Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			52
		Item 5.		Other Information			52
		Item 6.		Exhibits			53
Signature							54
Thirty-Ninth Supplemental Indenture
Sixth Supplemental Indenture
Section 302 Certification of Chief Executive Officer
Section 302 Certification of Chief Financial Officer
Section 906 Certification of Chief Executive Officer
Section 906 Certification of Chief Financial Officer

Definitions

Company		DTE Energy Company and any subsidiary companies
CTA		Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
Customer Choice		Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas
Detroit Edison		The Detroit Edison Company, a direct wholly-owned subsidiary of DTE Energy, and any subsidiary companies
DTE Energy		DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GCR		A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers
MDEQ		Michigan Department of Environmental Quality
MichCon		Michigan Consolidated Gas Company, an indirect wholly-owned subsidiary of DTE Energy, and any subsidiary companies
MISO		Midwest Independent System Operator, a Regional Transmission Organization
MPSC		Michigan Public Service Commission
Non-utility		An entity that is not a public utility; its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC or the FERC
NRC		Nuclear Regulatory Commission
Production tax credits		Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code designed to stimulate investment in and development of alternate fuel sources; the amount of a production tax credit can vary each year as determined by the Internal Revenue Service
Proved reserves		Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions
PSCR		A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses
Securitization		Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly owned special purpose entity, the Detroit Edison Securitization Funding LLC
SFAS		Statement of Financial Accounting Standards
Stranded Costs		Costs incurred by utilities in order to serve customers in a regulated environment that, absent special regulatory approval, would not otherwise be recoverable if customers switch to alternative energy suppliers
Subsidiaries		The direct and indirect subsidiaries of DTE Energy Company
Synfuels		The fuel produced through a process involving chemically modifying and binding particles of coal, used for power generation and coke production; synfuel production through December 31, 2007 generated production tax credits
Unconventional Gas		Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations
Units of Measurement
Bcf		Billion cubic feet of gas
Bcfe		Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil
GWh		Gigawatthour of electricity
kWh		Kilowatthour of electricity
Mcf		Thousand cubic feet of gas
MMcf		Million cubic feet of gas
MW		Megawatt of electricity
MWh		Megawatthour of electricity

Forward-Looking Statements

Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

	•		the potential requirement to refund proceeds received from synfuel partners;
	•		the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;
	•		the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
	•		economic climate and population growth or decline in the geographic areas where we do business;
	•		environmental issues, laws, regulations, and the cost of remediation and compliance, including potential new federal and state requirements that could include carbon and more stringent mercury emission controls, a renewable portfolio standard and energy efficiency mandates;
	•		nuclear regulations and operations associated with nuclear facilities;
	•		impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs;
	•		employee relations and the impact of collective bargaining agreements;
	•		unplanned outages;
	•		access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;
	•		the timing and extent of changes in interest rates;
	•		the level of borrowings;
	•		changes in the cost and availability of coal and other raw materials, purchased power and natural gas;
	•		effects of competition;
	•		impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;
	•		contributions to earnings by non-utility subsidiaries;
	•		changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
	•		the ability to recover costs through rate increases;
	•		the availability, cost, coverage and terms of insurance;
	•		the cost of protecting assets against, or damage due to, terrorism;
	•		changes in and application of accounting standards and financial reporting regulations;
	•		changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;
	•		amounts of uncollectible accounts receivable;
	•		binding arbitration, litigation and related appeals;
	•		changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company; and
	•		timing, terms and proceeds from any asset sale or monetization.

New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

Part I – Item 2.

DTE ENERGY COMPANY
Management’s Discussion and Analysis
of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with 2007 annual revenues in excess of $8 billion and assets of approximately $24 billion. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

Net income in the first quarter of 2008 was $212 million, or $1.30 per diluted share, compared to net income of $134 million, or $0.76 per diluted share, in the first quarter of 2007. The increase in net income is primarily due to the $82 million after-tax gain on the sale of a portion of Barnett shale properties, larger mark-to-market gains in Energy Trading, partially offset by reduced earnings from our discontinued Synfuels operations.

The items discussed below influenced our current financial performance and may affect future results:

•		Effects of weather on utility operations;
•		Collectibility of accounts receivable on utility operations;
•		Impact of regulatory decisions on utility operations;
•		Impact of legislation on utility operations;
•		Impact of increased demand on our coal supply;
•		Challenges associated with nuclear fuel;
•		Monetization of our Unconventional Gas Production business;
•		Planned monetization of our Power and Industrial Projects business;
•		Results in our Energy Trading business;
•		Discontinuance of the Synthetic Fuel business; and
•		Cost reduction efforts and required environmental and reliability-related capital investments.

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

UTILITY OPERATIONS

Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan.

Our Gas Utility segment consists of MichCon and Citizens Gas Fuel Company (Citizens). MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.3 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Effects of Weather on Utility Operations – Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. During the first quarter of 2008, we experienced colder weather than in the first quarter of 2007.

Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure, resulting in power outages. Restoration and other costs associated with storm-related power outages lowered pretax earnings by approximately $12 million in the first quarter of 2008 as compared to $15 million in the first quarter of 2007.

Collectibility of Accounts Receivable on Utility Operations – Both utilities continue to experience high levels of past due receivables, primarily attributable to economic conditions, higher energy prices and a lack of adequate levels of assistance for low-income customers.

We have taken aggressive actions to reduce the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers. We experienced an increase in our allowance for doubtful accounts expense for the two utilities to approximately $42 million for the three months ended March 31, 2008, compared to $29 million for the corresponding period of 2007.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. The MPSC approved the 2005 annual reconciliation in December 2006, allowing MichCon to surcharge $11 million beginning in January 2007. The MPSC approved the 2006 annual reconciliation in December 2007, allowing MichCon to surcharge $33 million beginning in January 2008. We filed the 2007 reconciliation in March 2008, requesting an additional surcharge of approximately $34 million including a $1 million uncollected balance from the 2005 surcharge. We accrue interest income on the outstanding balances.

Impact of Regulatory Decisions on Utility Operations – Detroit Edison filed a general rate case in April 2007 requesting a $123 million, or 2.9%, average increase in Detroit Edison’s annual revenue requirement for 2008, and in August 2007 filed a supplement to this filing to account for certain recent events. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. Also, the Michigan legislature enacted the Michigan Business Tax (MBT) in July 2007. The supplemental filing addressed the recovery of the merger control premium costs and the enactment of the MBT. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million. In February 2008, Detroit Edison filed an update to its April 2007 rate case filing, which includes the use of 2009 as the projected test year; a revised 2009 load forecast; 2009 estimates on environmental and advanced metering infrastructure capital expenditures; and adjustments to the MBT calculation. See Note 6 of the Notes to Consolidated Financial Statements.

The MPSC issued an order in August 2006 approving a settlement agreement providing for an annualized 2006 rate reduction of $53 million for Detroit Edison, effective September 2006. Beginning January 1, 2007 and continuing until April 13, 2008, one year from the April 13, 2007 general rate case filing, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $18 million for the three months ended March 31, 2008 and 2007, as a result of this order. The revenue reduction is net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provides for some level of realignment of the existing rate structure by allocating a larger percentage of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was approved by the MPSC that provides for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provides for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, have enabled 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54 million. This settlement provides for MichCon to retain the proceeds from the sale of 3.6 Bcf of gas, which MichCon expects to sell through 2009. During 2007, MichCon sold 0.75 Bcf of base gas and recognized a pre-tax gain of $5 million. MichCon did not sell base gas in the first quarter of 2008. By enabling MichCon to retain the profit from the sale of this gas, the settlement provides MichCon with the opportunity to earn an 11% return on equity with no customer rate increase for a period of five years from 2005 to 2010.

Impact of Legislation on Utility Operations – In April 2008, a package of bills to establish a sustainable, long-term energy plan was passed by the Michigan House of Representatives. Key provisions of the bills include:

	•		A 10 percent limit on the electric Customer Choice program. Once customers representing 10 percent of a utility’s load have elected to receive their generation from an alternate electricity supplier, remaining customers would be maintained on full, bundled utility service. As of March 31, 2008, approximately 2 percent of Detroit Edison’s load was on the electric Customer Choice program. The bill also codifies prior MPSC requirements for customers returning to full utility service.
	•		A requirement that the MPSC set rates based on cost-of-service for all customer classes, eliminating the current subsidy for residential customers included in business customer rates. Elimination of the subsidy (de-skewing) would be phased in over a five year period. Rates for schools and other qualified educational institutions would be immediately set at their cost of service.
	•		A 12 month hard-stop deadline for the MPSC to complete a rate case and the ability for the utility to self-implement rate changes six months after a rate filing, bringing Michigan in line with many other states. If the final rate case order leads to lower rates than the utility had self-implemented, the utility would refund, with interest, the difference. In addition, utility rate cases would be based on a forward test year. The bill also provides organizational changes which may enable the MPSC to obtain increased funding to hire staff to meet the new timetable.
	•		A Certificate of Need (CON) process for capital projects costing more than $500 million. The MPSC would be required to review for prudency proposed investments in new generating assets, acquisition of existing power plants, major upgrades of power plants, and long-term power purchase agreements. Utilities would also be provided the opportunity to recover interest expense during construction. As part of the CON process, the MPSC would be directed to establish and approve a financing plan and the recovery of new investments in customer rates.
	•		A review and approval process, including evaluation criteria, for the MPSC for proposed utility merger and acquisitions in Michigan.
	•		A renewable portfolio standard (RPS) of 4% by 2012 and 10% by 2015. Qualifying renewable energy sources would include wind, biomass, solar, hydro, geothermal, waste industrial gases and industrial thermal energy. After passage of the new law, the MPSC would establish a per meter surcharge to fund the RPS requirements. The monthly surcharge is limited to $3 for residential customers, $16.58 for commercial customers and $187.50 for industrial customers. The recovery mechanism starts prior to actual construction in order to smooth the rate impact for customers. Within 5 months of the passage of the new law, the utilities would file an RPS plan with the MPSC. A utility will not have to comply with the RPS standards if the MPSC determines that the added costs of meeting the RPS standard exceed the per meter caps. The bills specify that a utility can build up to 33 percent of the generation required to meet the RPS. An additional 33 percent would be developed by others and sold to the utility. The remaining renewable generation would be contracted through long-term power purchase agreements (PPA).
	•		A requirement for utilities to create specific efficiency programs for each customer class including incentives for meeting performance goals. For electric sales, the program would target 0.3 percent annual savings in 2008/2009, ramping up to 1 percent annual savings by 2012. For natural gas sales, the targeted annual savings start at 0.1 percent in 2008/2009 before ramping up to 0.75 percent by 2012. The MPSC may allow a utility to recover over time the actual costs of its efficiency programs in base rates. Costs would be limited to 2 percent maximum of total utility revenues (1.5 percent of business revenues). The bill would also allow a natural gas utility that spends at least 0.5 percent of its revenues on energy efficiency programs to decouple revenues from volumetric sales, adjusting for sales volumes above or below forecasted levels. Similar to the RPS bills, a cost test would be implemented to ensure reasonable costs. If a utility spends at the MPSC approved levels, it would be considered in full compliance even if the savings targets are not met.

The bills move to the Michigan Senate where action is anticipated by mid-summer 2008. We are unable to predict the outcome of the legislative process and the impact of the legislative process on the Company.

 

Impact of Increased Demand on our Coal Supply - Our generating fleet produces approximately 79% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in significant price increases. In addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal have resulted in decreasing coal output from the central Appalachian region. Furthermore, as a result of environmental regulation and declining eastern coal stocks, demand for cleaner burning western coal has increased.

Challenges Associated with Nuclear Fuel - We operate one nuclear facility that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold; this fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. We are a party in litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage and have begun work on an on-site dry cask storage facility.

NON-UTILITY OPERATIONS

We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the sale, restructuring or recapitalization of certain non-utility businesses.

Coal and Gas Midstream

Coal and Gas Midstream consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

Coal Transportation and Marketing provides fuel, transportation, storage, blending and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. We perform coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users or for small power generation projects. We plan to continue to build our capacity to transport greater amounts of western coal, and have expanded our coal storage and blending capacity with the start of commercial operation of our coal terminal in Chicago in April 2007.

Pipelines, Processing and Storage owns partnership interests in two interstate transmission pipelines and two natural gas storage fields. The pipeline and storage assets are primarily supported by stable, long-term, fixed-price revenue contracts. The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance and technical support for Washington 28 and Washington 10 storage facilities. Pipelines, Processing and Storage is continuing its steady growth plan of storage capacity expansion, with two new expansions and the expanding and building of new pipeline capacity to serve markets in the Midwest and Northeast United States.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 53,639, net of impairments (52,251 acres, net of interest of others). We continue to acquire select positions in active development areas in the Barnett shale to optimize our existing portfolio.

Monetization of our Unconventional Gas Production Business – On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to standard post-closing adjustments. The properties sold included 186 Bcf of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale. The Company recognized a pre-tax gain of $126 million ($82 million after-tax) on the sale in the quarter ended March 31, 2008.

We plan to retain our holdings in the western portion of the Barnett shale and anticipate significant opportunities to develop our current position while accumulating additional acreage in and around our existing assets. Recent increases in natural gas prices and successes within the Barnett shale are resulting in additional capital being invested into the area. We invested approximately $28 million in the Barnett shale for the first three months of 2008 and expect to invest an additional $65 million to $70 million during the remainder of the year. During 2008, we expect to drill 30 new wells and achieve Barnett shale production of approximately 5 Bcfe to 6 Bcfe of natural gas from our remaining properties, compared with approximately 7.7 Bcfe in 2007 from all properties, including those that were sold.

Power and Industrial Projects

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, and biomass energy projects. This business provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. Services include pulverized coal and petroleum coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate one gas-fired peaking electric generating plant and a biomass-fired electric generating plant. In addition, we operate a coal-fired power plant under contract that is currently not in service. This business also develops, owns and operates landfill gas recovery systems throughout the United States, and produces metallurgical coke from three coke batteries. The production of coke from these coke batteries generates production tax credits.

Planned Monetization of our Power and Industrial Projects Business – We expect to sell a 50% interest in a portfolio of select Power and Industrial Projects. In addition to the proceeds that the Company will receive from the sale of its 50% equity interest in this portfolio of projects (Projects), the company that will own the Projects will obtain debt financing, with proceeds distributed to DTE Energy immediately prior to the sale of the equity interest. Timing of this transaction is highly dependent on availability of acceptable equity and debt financing terms in the credit markets. As a result, the Company cannot predict the outcome or timing with certainty. In connection with the sale, the Company will enter into a management services agreement to manage the day-to-day operations and to act as the managing member of the company that owns the Projects. We plan to account for our 50% ownership interest using the equity method. The assets and liabilities of the Projects are classified as held for sale as of March 31, 2008.

Energy Trading

Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in the recognition of unrealized gains and losses from changes in the fair value of the derivatives in our results of operations. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.

Results in our Energy Trading Business – Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipelines and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipelines and certain storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.

DISCONTINUED OPERATIONS

Synthetic Fuel

Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation effective December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits. The value of a production tax credit is adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value is reduced if the Reference Price of a barrel of oil exceeds certain thresholds. The actual tax credit phase-out for 2007 was approximately 67%.

PERFORMANCE EXCELLENCE PROCESS

We continuously review and adjust our cost structure and seek improvements in our processes. In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process. This initiative was an extension of the DTE Energy Operating System initiative adopted in 2002. These initiatives represent the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements.

The primary goal is to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their rates. Additionally, we will need significant resources in the future to invest in the infrastructure required to provide safe, reliable and affordable energy. Specifically, we began a series of focused improvement initiatives within our Electric and Gas Utilities, and our corporate support function. The process is rigorous and challenging and seeks to yield sustainable performance improvements to our customers and shareholders. We have identified continuous improvement opportunities, including the Performance Excellence Process. To fully realize the benefits from this program, it was necessary to make significant up-front investments in our infrastructure and business processes, and we began to realize sustained net cost savings in 2007.

In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental costs to achieve (CTA). Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $102 million and $54 million of CTA in 2006 and 2007, respectively, as a regulatory asset and began amortizing deferred costs in 2007 as the recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding. Amortization of prior year deferred CTA costs was $4 million and $3 million for the three months ended March 31, 2008 and 2007, respectively. Detroit Edison deferred approximately $4 million and $13 million of CTA for the three months ended March 31, 2008 and 2007, respectively. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon expects to seek a recovery mechanism in its next rate case in 2009.

CAPITAL INVESTMENT

We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. From 2008 through 2012, our electric utility segment currently expects to invest approximately $5.3 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects. Our gas utility segment currently expects to invest approximately $1.0 billion on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

OUTLOOK

The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth.

Looking forward, we will focus on several areas that we expect will improve future performance:

	•		Continuing to pursue regulatory stability and investment recovery for our utilities;
	•		Managing the growth of our utility asset base;
	•		Enhancing our cost structure across all business segments;
	•		Improving our Electric and Gas Utility customer satisfaction; and
	•		Investing in businesses that integrate our assets and leverage our skills and expertise.

We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.

RESULTS OF OPERATIONS

Net income in the first quarter of 2008 was $212 million, or $1.30 per diluted share, compared to net income of $134 million, or $0.76 per diluted share, in the first quarter of 2007. The increase in net income is primarily due to the $82 million after-tax gain on the sale of a portion of Barnett shale properties and larger mark-to-market gains in Energy Trading, partially offset by reduced earnings from our discontinued Synfuels operations. The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

Net income by segment for the three months ended March 31, 2008 and 2007 is as follows:

		Three Months Ended
		March 31
(in Millions, except per share data)		2008				2007
Net Income:
Electric Utility		$	41			$	40
Gas Utility			59				67
Non-Utility Operations:
Coal and Gas Midstream			8				12
Unconventional Gas Production			82				2
Power and Industrial Projects			10				4
Energy Trading			31				1
Corporate & Other			(31	)			(30	)
Income (Loss) from Continuing Operations:
Utility			100				107
Non-utility			131				19
Corporate & Other			(31	)			(30	)
			200				96
Discontinued Operations			12				38
Net Income		$	212			$	134

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Factors impacting income: Net income increased $1 million in the first quarter of 2008 compared to the same period in 2007 due to higher gross margins partially offset by higher operating expenses.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	1,153			$	1,094
Fuel and Purchased Power			402				354
Gross Margin			751				740
Operation and Maintenance			358				348
Depreciation and Amortization			192				182
Taxes Other Than Income			62				72
Other Asset (Gains), Losses and Reserves, Net			—				7
Operating Income			139				131
Other (Income) and Deductions			74				71
Income Tax Provision			24				20
Net Income		$	41			$	40
Operating Income as a Percentage of Operating Revenues			12	%			12	%

Gross margin increased $11 million in the first quarter of 2008 as compared to the same period in 2007. The increase in 2008 was attributed to higher margins due to returning sales from electric Customer Choice and service territory performance, partially offset by reductions in revenues for over-collections of our Regulatory Asset Recovery Surcharge (“RARS”) and our recoverable pension cost. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.

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

Increase (Decrease) in Gross Margin Components Compared to Prior Year

		Three Months
(in Millions)
Weather related margin impacts		$	3
Return of customers from electric Customer Choice			8
Service territory performance			8
RARS over-collection			(3	)
Recoverable pension cost			(4	)
Other, net			(1	)
Increase in gross margin		$	11

		Three Months Ended
Power Generated and Purchased		March 31
(in Thousands of MWh)		2008				2007
Power Plant Generation
Fossil			10,240				10,557
Nuclear			2,343				2,428
			12,583				12,985
Purchased Power			1,730				1,233
System Output			14,313				14,218
Less Line Loss and Internal Use			(845	)			(784	)
Net System Output			13,468				13,434
Average Unit Cost ($/MWh)
Generation (1)		$	16.60			$	15.41
Purchased Power		$	61.60			$	63.88
Overall Average Unit Cost		$	22.04			$	19.62

		Three Months Ended
		March 31
(in Thousands of MWh)		2008				2007
Electric Sales
Residential			3,932				3,786
Commercial			4,362				4,309
Industrial			3,516				3,374
Wholesale			723				735
Other			109				110
			12,642				12,314
Interconnections sales (1)			826				1,120
Total Electric Sales			13,468				13,434
Electric Deliveries
Retail and Wholesale			12,642				12,314
Electric Customer Choice			398				451
Electric Customer Choice – Self Generators (2)			58				67
Total Electric Sales and Deliveries			13,098				12,832

Operation and maintenance expense increased $10 million in the first quarter of 2008 compared to the same period in 2007 primarily due to $7 million of increased uncollectible expense and $3 million of higher labor expense.

Depreciation and amortization expense increased $10 million in the first quarter of 2008 compared to the same period in 2007. The 2008 increase is attributed to $4 million of higher software amortization primarily due to the Enterprise Business System implementation in the second quarter of 2007, increased depreciation of $3 million due to higher levels of depreciable plant and $2 million of increased amortization of our regulatory assets.

Taxes other than income decreased $10 million in the first quarter of 2008 compared to the same period in 2007 due to a $9 million decrease in Michigan Single Business Tax (SBT) expense, which was replaced with the Michigan Business Tax (MBT) in 2008 and accounted for in the Income tax provision.

Other asset (gains), losses and reserves, net expense decreased $7 million in the first quarter of 2008 due to a $7 million reserve established in 2007 for a loan guaranty related to our former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).

Outlook – We will move forward in our efforts to continue to improve the operating performance of Detroit Edison. We continue to resolve outstanding regulatory issues and continue to pursue additional regulatory and/or legislative solutions for structural problems within the Michigan electric market, primarily electric Customer Choice and the need to adjust rates for each customer class to reflect the full cost of service. We expect cash flows and operating performance to continue to be at risk due to the electric Customer Choice program until the issues associated with this program are resolved. We are also seeking regulatory reform to ensure more timely cost recovery and resolution of rate cases. If enacted, these issues would be addressed, for the most part, by the package of bills to establish a sustainable long-term energy plan recently passed by the Michigan House of Representatives, discussed more fully in the Overview section. Looking forward, additional issues, such as rising prices for coal and other commodities, health care and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will continue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. We intend to seek recovery of these investments in future rate cases.

Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in over 20 years. Should our regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant. We have not decided on construction of a new base-load nuclear plant; however, in February 2007 we announced preparation of a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. By completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005. We are also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.

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

	•		The amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
	•		Our ability to reduce costs and maximize plant and distribution system performance;
	•		Variations in market prices of power, coal and gas;
	•		Economic conditions within Michigan;
	•		Weather, including the severity and frequency of storms;
	•		The level of customer participation in the electric Customer Choice program; and
	•		Any potential new federal and state environmental, renewable energy and energy efficiency requirements.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Factors impacting income: Net income decreased $8 million in the first quarter of 2008 compared to the same period in 2007 due to higher operation and maintenance expense and increased depreciation and amortization expense, partially offset by higher gross margins.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	915			$	874
Cost of Gas			654				623
Gross Margin			261				251
Operation and Maintenance			123				111
Depreciation and Amortization			24				21
Taxes Other Than Income			14				14
Other Asset Losses and Reserves, Net			—				3
Operating Income			100				102
Other (Income) and Deductions			15				12
Income Tax Provision			26				23
Net Income		$	59			$	67
Operating Income as a Percentage of Operating Revenues			11	%			12	%

Gross margin increased $10 million in the first quarter of 2008 as compared to the same period in 2007. This increase is due to an $11 million favorable impact in lost gas recognized and a $4 million increase from the favorable impact of weather, partially offset by a $5 million decrease due to lower transportation and service charges. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.

		Three Months Ended
		March 31
		2008				2007
Gas Markets (in Millions)
Gas sales		$	819			$	773
End user transportation			51				52
			870				825
Intermediate transportation			19				19
Storage and other			26				30
		$	915			$	874
Gas Markets (in Bcf)
Gas sales			71				70
End user transportation			44				49
			115				119
Intermediate transportation			116				128
			231				247

Operation and maintenance expense increased $12 million in the first quarter of 2008 compared to the same period in 2007 primarily due to an $11 million increase in uncollectible expense.

Depreciation and amortization expense increased $3 million in the first quarter of 2008 compared to the same period in 2007. In the first quarter of 2007, we recorded a $3 million adjustment resulting from an MPSC order related to pipeline assets.

Other asset losses and reserves, net expense decreased $3 million in the first quarter of 2008 compared to the same period in 2007. In the first quarter of 2007, we recorded a $3 million adjustment attributable to an MPSC disallowance of certain costs related to the acquisition of pipeline assets.

Outlook – Operating results are expected to vary due to regulatory proceedings, weather, changes in economic conditions, customer conservation, process improvements, volatility in the short-term storage markets which impact third party storage revenues and base gas sales. Higher gas prices and economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s uncollectible true-up mechanism and GCR mechanism.

We will continue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

NON-UTILITY OPERATIONS

Coal and Gas Midstream

Our Coal and Gas Midstream segment consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.

Factors impacting income: Net income decreased $4 million in the first quarter of 2008 compared to the same period in 2007 due to a decrease in operating revenues from our coal business as a result of the lost business from the discontinuance of our Synfuel operations and a reduction in trading margins. This was partially offset by an increase of over $2 million from the pipelines, processing and storage businesses.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	159			$	227
Operation and Maintenance			146				206
Depreciation and Amortization			3				2
Taxes Other Than Income			1				1
Operating Income			9				18
Other (Income) and Deductions			(4	)			(1	)
Income Tax Provision			5				7
Net Income		$	8			$	12

Operating revenues decreased $68 million in the first quarter of 2008 compared to the same period in 2007 as a result of lost business from the discontinuance of our Synfuel operations of $30 million and a reduction in trading volumes.

Operations and maintenance expense decreased $60 million in the first quarter of 2008 compared to the same period in 2007. The decrease is attributed to the lost business from the discontinuance of the Synfuel operations and a reduction in trading volumes.

Outlook – We expect to see a decrease in net income through the rest of 2008, since approximately $11 million of our annual 2007 Coal Transportation and Marketing net income was dependent upon our Synfuel operations that ceased operations at the end of 2007. Beyond 2008, we expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments.

Our Pipelines, Processing and Storage business expects to continue its steady growth plan. In April 2008, Washington 28’s increased storage capacity of 6 Bcf was placed in service, increasing the total to 16 Bcf. Also, in April 2008, Washington 10’s Shelby 2 storage field was placed in service creating an additional 4 Bcf of storage capacity. The

Shelby 2 storage capacity will be expanded over the next two years by 8 Bcf, increasing Washington 10’s storage capacity to a total of 74 Bcf. Vector Pipeline placed into service its Phase 1 expansion for approximately 200 MMcf/d in November 2007. This project is fully supported by customers with long-term agreements. In addition, Vector Pipeline requested permission from the FERC in the fourth quarter of 2007 to build one additional compressor station and to expand the Vector Pipeline by approximately 100 MMcf/d, with a proposed in-service date of November 1, 2009. Adding another compressor station will bring the system from its current capacity of about 1.2 Bcf/d up to 1.3 Bcf/d in 2009. Pipelines, Processing and Storage has a 26% ownership interest in Millennium Pipeline which commenced construction in June 2007 and is scheduled to be in service in late 2008. We plan to expand existing assets and develop new assets which are typically supported with long-term customer commitments.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in northern Texas. In June 2007, we sold our Antrim shale gas exploration and production business in northern Michigan for gross proceeds of $1.3 billion.

On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to standard post-closing adjustments. The properties sold included 186 Bcf of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale. We recognized a pre-tax gain of $126 million ($82 million after-tax) on the sale for the quarter ended March 31, 2008.

Factors impacting income: Net income increased $80 million in the first quarter of 2008 compared to the same period in 2007 due to the gain recognized on the sale of our shale property. Lower sales volumes were offset by higher commodity prices in the first quarter of 2008 compared to 2007.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	10			$	28
Operation and Maintenance			6				11
Depreciation, Depletion and Amortization			2				7
Taxes Other Than Income			—				3
Other Asset (Gains)			(126	)			—
Operating Income			128				7
Other (Income) and Deductions			—				4
Income Tax Provision			46				1
Net Income		$	82			$	2

Operating revenues and operation and maintenance expense were both lower in the first quarter of 2008 compared to the same period in 2007 as a result of our monetization initiatives. For the first quarter of 2008, Barnett shale production was approximately 1.0 Bcfe of natural gas compared with approximately 1.5 Bcfe during the same period in 2007.

Outlook – We plan to retain our holdings in the western portion of the Barnett shale and anticipate significant opportunities to develop our current position while accumulating additional acreage in and around our existing assets. Recent increases in natural gas prices and successes within the Barnett shale are resulting in additional capital being invested into the area. We invested approximately $28 million in the Barnett shale for the first three months of 2008 and expect to invest an additional $65 million to $70 million during the remainder of the year. During 2008, we expect to drill 30 new wells and achieve Barnett shale production of approximately 5 Bcfe to 6 Bcfe of natural gas from our remaining properties, compared with approximately 7.7 Bcfe in 2007 from all properties, including those that were sold.

Power and Industrial Projects

Our Power and Industrial Projects segment is comprised primarily of projects that deliver utility-type products and services to industrial, commercial and institutional customers and biomass energy projects.

Factors impacting income: Net income increased $6 million in the first quarter of 2008 as compared to the same period in 2007. The 2008 increase is attributed to lower depreciation and amortization expense and higher asset gains partially offset by higher operation and maintenance expense.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	109			$	110
Operation and Maintenance			96				90
Depreciation and Amortization			3				11
Taxes Other Than Income			3				4
Asset (Gains) Losses and Reserves, Net			(3	)			—
Operating Income			10				5
Other (Income) and Deductions			(3	)			3
Minority Interest			—				1
Income Taxes
Provision (Benefit)			5				1
Production Tax Credits			(2	)			(4	)
			3				(3	)
Net Income		$	10			$	4

Operating revenues decreased $1 million in the first quarter of 2008 compared to the same period in 2007.  The decrease is attributed to an $8 million reduction in revenues at a pulverized coal facility as a result of a customer purchasing change which resulted in coal being sourced directly from the supplier, and a $2 million decrease at our pulp and paper facility due to decreased volumes. These decreases were partially offset by $2 million of increased revenue from other steel projects due to higher coke pricing, $2 million of increased revenue at our petroleum coke facility due to increased volumes and pricing, and $5 million of increased revenue at our on-site energy projects representing project revenues at new facilities.

Operation and maintenance expense increased $6 million in the first quarter of 2008 compared to the same period in 2007.  This increase is due primarily to $14 million in increased payroll and other overhead costs at multiple project facilities as well as increased corporate development costs.  The increases are offset by an $8 million reduction in expenses at a pulverized coal facility as a result of a customer purchasing change which resulted in coal being sourced directly from the supplier.  

Depreciation and amortization expense decreased $8 million in the first quarter of 2008 compared to the same period in 2007. The decrease is due to the classification of our monetization project companies as held for sale as of September 30, 2007, resulting in depreciation and amortization not being recognized for those assets in the first quarter of 2008.

Assets (gains) losses and reserves, net gain increased $3 million in the first quarter of 2008 as compared to the first quarter of 2007. This gain is attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production. We now recognize excess cash receipts as gains as we have fully recovered our cost basis.

Outlook – We expect to sell a 50% interest in a portfolio of select Power and Industrial Projects. In addition to the proceeds that we will receive from the sale of our 50% equity interest in this portfolio of projects (Projects), the company that will own the Projects will obtain debt financing, with proceeds distributed to DTE Energy immediately prior to the sale of the equity interest. Timing of this transaction is highly dependent on availability of acceptable equity and debt financing terms in the credit markets. As a result, we cannot predict the outcome or timing with certainty. In connection with the sale, we will enter into a management services agreement to manage the day-to-day operations and

to act as the managing member of the company that owns the Projects. We plan to account for our 50% ownership interest using the equity method. The assets and liabilities of the Projects are classified as held for sale as of March 31, 2008.

Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business.

Energy Trading

Our Energy Trading segment focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelines and storage, and power transmission and generating capacity positions.

Factors impacting income: Net income increased $30 million in the first quarter of 2008 compared to the same period in 2007. This change was largely due to an increase in mark-to-market gains in our gas trading strategies and higher realized margins from our gas storage portfolio.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	288			$	212
Fuel, Purchased Power and Gas			219				193
Gross Margin			69				19
Operation and Maintenance			16				13
Depreciation, Depletion and Amortization			1				1
Taxes Other Than Income			1				—
Operating Income			51				5
Other (Income) and Deductions			1				3
Income Tax Provision			19				1
Net Income		$	31			$	1

Gross margin increased $50 million in the first quarter of 2008 compared to the first quarter of 2007. This increase is primarily attributed to an increase in unrealized margins of $42 million and higher realized margins of $8 million.

The increase in unrealized margins was due to $33 million, primarily in our gas trading strategies as well as $16 million of improved margins in our power strategies. The mark-to-market favorability in our gas and power positions was partially offset by the absence of $7 million first quarter 2007 unrealized gains in our oil trading portfolio due to timing differences.

Higher realized margins were primarily due to $15 million favorability and $3 million favorability from our gas storage and oil strategies, respectively. During the first quarter of 2007, our earnings were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage as a result of the current price in natural gas and an increase in the forward prices for such gas. Offsetting the realized gas margins favorability were lower realized power positions of $10 million.

Operation and maintenance expense increased $3 million in the first quarter of 2008 compared to the same period in 2007 due to higher payroll and incentive costs.

Outlook – Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions of natural gas storage, natural gas pipelines, and power transmission and full requirements contracts. The financial instruments are deemed derivatives, whereas the proprietary gas inventory, pipelines, transmission contracts, certain full requirements contracts and storage assets are

not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar year, but runs annually from April of one year to March of the next year. Energy Trading’s strategy is to economically manage the price risk of storage with futures and over-the-counter forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.

See also the “Fair Value” section that follows.

CORPORATE & OTHER

Corporate & Other results includes various corporate staff functions. These functions support the entire Company; therefore, their costs are fully allocated to the various segments based on services utilized. As a result, the effect of the allocation on each segment can vary from year to year. Corporate & Other also holds certain non-utility debt and energy-related investments.

Factors impacting income: Net income decreased $1 million in the first quarter of 2008 compared with the same period in 2007 primarily due to $7 million of unrealized losses from natural gas forward contracts that were retained by the Company after the Antrim shale sale in the second quarter of 2007. The decrease was partially offset by lower interest expense due to a decrease in short-term borrowings.

DISCONTINUED OPERATIONS

Synthetic Fuel

We discontinued the operations of our synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel business generated operating losses that were substantially offset by production tax credits.

The incentive provided by production tax credits was designed to reduce and phase out if the price of oil increased to the point of providing significant market incentives for the production of synthetic fuels. As such, the tax credit in a given year was phased out if the reference price of oil within that year exceeded a threshold price. As of December 31, 2007, the reference price exceeded the threshold and the tax credit value was reduced by an estimated phase-out percentage of 69%. Reserves for expected refunds of partner payments for production tax credits were recorded at December 31, 2007 based on this estimated phase-out percentage. An adjustment to the reserves was recorded in the first quarter of 2008 to reflect the actual 67% phase-out percentage based on the actual IRS Reference Price and inflation factor published by the IRS in March 2008. This adjustment to the phase-out percentage resulted in a pre-tax gain from discontinued operations of $12 million during the three months ended March 31, 2008.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Operating Revenues		$	7			$	267
Operation and Maintenance			8				324
Depreciation, Depletion and Amortization			(1	)			1
Taxes Other Than Income			—				4
Asset (Gains), Losses and Reserves, Net			(16	)			(36	)
Operating Income (Loss)			16				(26	)
Other (Income) and Deductions			(1	)			(4	)
Minority Interest			—				(59	)
Income Taxes
Provision			6				13
Production Tax Credits			(1	)			(14	)
			5				(1	)
Net Income		$	12			$	38

Operating revenues decreased $260 million in the first quarter of 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 first quarter activity reflects the increased value of 2007 synfuel production as a result of final determination of the IRS Reference Price and inflation factor.

Operation and maintenance expense decreased $316 million in the first quarter of 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 first quarter activity reflects adjustments to 2007 contractually defined cost sharing mechanisms with suppliers, as determined by applying the actual phase-out percentage.

Asset (gains), losses and reserves, net gain decreased $20 million in the first quarter of 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 first quarter activity reflects the impact of reserve adjustments for the final phase-out percentage.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES AND NEW ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff Position FAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See also the “Fair Value” section.

See also Notes 2 and 3 of the Notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. During the first quarter of 2008, our cash requirements were met primarily through operations and from our non-utility monetization program. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.

		Three Months Ended
		March 31
(in Millions)		2008				2007
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income		$	212			$	134
Depreciation, depletion and amortization			225				225
Deferred income taxes			190				(6	)
Gain on sale of non-utility assets			(126	)			—
Gain on sale of synfuel and other assets, net			(20	)			(25	)
Working capital and other			411				304
			892				632
Investing activities:
Plant and equipment expenditures — utility			(277	)			(306	)
Plant and equipment expenditures — non-utility			(52	)			(69	)
Proceeds from sale of non-utility assets			250				—
Proceeds from sale of synfuels and other assets			61				110
Restricted cash and other investments			37				41
			19				(224	)
Financing activities:
Redemption of long-term debt			(79	)			(77	)
Repurchase of long-term debt			(238	)			—
Short-term borrowings, net			(534	)			(185	)
Repurchase of common stock			(13	)			(55	)
Dividends on common stock and other			(90	)			(94	)
			(954	)			(411	)
Net Decrease in Cash and Cash Equivalents		$	(43	)		$	(3	)

Cash from Operating Activities

A majority of our operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. Our non-utility businesses also provide sources of cash flow to the enterprise, primarily from the synthetic fuels business, which we believe, subject to considerations discussed below, will provide up to approximately $200 million of net cash impacts in 2008 and 2009.

Cash from operations in the first quarter of 2008 increased $260 million from the comparable 2007 period. The operating cash flow comparison primarily reflects an increase in net income after adjusting for non-cash items (depreciation, depletion and amortization and deferred taxes) and gains on sales of businesses.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets. Net cash from investing activities increased $243 million in the first quarter of 2008 compared to the same period in 2007. The 2008 change was primarily driven by our non-utility monetization program.

Cash from Financing Activities

We rely on both short-term borrowings and long-term financing as a source of funding for our capital requirements not satisfied by our operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.

Net cash used for financing activities increased $543 million during the first quarter of 2008 compared to the same period in 2007, primarily due to the increased operating cash flow result and non-utility monetization activity in the 2008 period. In March 2008, we repurchased $238 million of tax-exempt bonds which were funded with other short-term borrowings. In April 2008, $69 million of the repurchased bonds was reissued and we expect the remainder to be issued within 90 days of the repurchase.

Outlook

We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We have incurred costs associated with implementation of our Performance Excellence Process, but we began to realize sustained net cost savings in 2007. We may also be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives.

We anticipate approximately $200 million of net synfuel-related cash impacts in 2008 and 2009, which consists of the final reconciliation of cash from synthetic fuel operations (related to activity prior to December 31, 2007), proceeds from option hedges, and tax credit carryforward utilization and other tax benefits that are expected to reduce future tax payments.

As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the sale, restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and an additional approximately $170 million in the first quarter of 2008 from the sale of a portion of Barnett shale properties. Additional proceeds will be realized upon the completion of the monetization of the Power and Industrial business as discussed above. Upon completion of our remaining monetization activities, we expect to repurchase an additional approximately $275 million of common stock and to use approximately $200 million to redeem outstanding debt, assuming the expected asset sales occur. Our objectives for cash redeployment are to increase shareholder value; strengthen the balance sheet and coverage ratios; improve our current credit rating and outlook; and to have any monetization be accretive to earnings per share.

We continue to monitor the impact, if any, of the current conditions in the credit markets on our operations. We believe that our access to financing at reasonable interest rates, the fair value of assets held in trust to satisfy future obligations for nuclear decommissioning and pension plans, and our counterparties’ creditworthiness will not be significantly affected by current conditions in the credit market. The overall credit market conditions have resulted in credit rating downgrades for bond insurers, and a loss of liquidity in the auction rate markets for their insured bonds. These conditions negatively impacted interest rates, including default rates in the case of failed auctions. As a result, the Company repurchased $238 million of variable rate tax-exempt bonds in March 2008 whose rates had been set in the auction market. We plan to hold the bonds in a weekly rate mode until which time we can either refinance and reissue the bonds or convert the bonds to a longer-term mode. In April 2008, we reissued $69 million of these tax-exempt bonds.

FAIR VALUE

SFAS No. 157 — Fair Value Measurements

Effective January 1, 2008, we adopted SFAS No. 157. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff Position FAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See Note 3 of the Notes to Consolidated Financial Statements.

Derivative Accounting

The accounting standards for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as “Assets or Liabilities from risk management and trading activities,” at the fair value of the contract. The recorded fair value of the contract is then adjusted at each reporting date, in the Consolidated Statements of Operations, to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting. Changes in the fair value of a designated derivative that is highly effective as a cash flow hedge are recorded as a component of Accumulated other comprehensive income, net of taxes, until the hedged item affects income. These amounts are subsequently reclassified into earnings as a component of the value of the forecasted transaction, in the same period as the forecasted transaction affects earnings. The ineffective portion of the fair value changes is recognized in the Consolidated Statements of Operations immediately.

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. To determine the fair value of contracts accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates and exercise periods.

Contracts we typically classify as derivative instruments include power, gas, certain coal and oil forwards, futures, options and swaps, and foreign currency contracts. Items we do not generally account for as derivatives (and which are therefore excluded from the following tables) include proprietary gas inventory, certain gas storage and transportation arrangements, and gas and oil reserves.

The subsequent tables contain the following four categories represented by their operating characteristics and key risks:

	•		Proprietary Trading — Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.
	•		Structured Contracts — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting transaction can be executed.
	•		Economic Hedges — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.
	•		Other — Primarily represents derivative activity associated with our gas reserves and discontinued synfuel operations. A portion of the price risk associated with anticipated production from the Barnett gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as “Assets or Liabilities from risk management and trading activities,” with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and synfuel proceeds including changes therein.

Roll-Forward of MTM Energy Contract Net Assets

The following tables provide details on changes in our MTM net asset (or liability) position for the three months ended March 31, 2008:

		Proprietary				Structured				Economic
(in Millions)		Trading				Contracts				Hedges				Other				Total
MTM at December 31, 2007		$	8			$	(365	)		$	4			$	2			$	(351	)
Reclassify to realized upon settlement			4				44				(11	)			(3	)			34
Changes in fair value recorded to income			38				(27	)			4				(1	)			14
Amortization of option premiums			(1	)			—				—				—				(1	)
Amounts recorded to unrealized income			41				17				(7	)			(4	)			47
Cumulative effect adjustment to initially apply SFAS No. 157, pre-tax			—				6				—				—				6
Amounts recorded in other comprehensive income			—				—				—				(6	)			(6	)
Change in collateral held by (for) others			1				(64	)			—				—				(63	)
Option premiums paid and other			3				(1	)			—				—				2
MTM at March 31, 2008		$	53			$	(407	)		$	(3	)		$	(8	)		$	(365	)

A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business was mitigated by financial contracts that hedged our price risk exposure through 2013. The contracts were retained when the Antrim business was sold and offsetting financial contracts were put into place to effectively settle these positions. The contracts will require payments through 2013. These contracts represent the majority of the above net mark-to-market liability.

The following table provides a current and noncurrent analysis of “Assets and Liabilities from risk management and trading activities,” as reflected on the Consolidated Statements of Financial Position as of March 31, 2008. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

		Proprietary				Structured				Economic												Assets
(in Millions)		Trading				Contracts				Hedges				Eliminations				Other				(Liabilities)
Current assets		$	58			$	284			$	15			$	(17	)		$	2			$	342
Noncurrent assets			23				232				6				(2	)			—				259
Total MTM assets			81				516				21				(19	)			2				601
Current liabilities			(28	)			(413	)			(21	)			17				(6	)			(451	)
Noncurrent liabilities			—				(510	)			(3	)			2				(4	)			(515	)
Total MTM liabilities			(28	)			(923	)			(24	)			19				(10	)			(966	)
Total MTM net assets (liabilities)		$	53			$	(407	)		$	(3	)		$	—			$	(8	)		$	(365	)

Maturity of Fair Value of MTM Energy Contract Net Assets

We manage our MTM risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).

We determine the MTM adjustment for our derivative contracts 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 or locations in which external market data is not readily observable, we estimate value using mathematical valuation models. 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.

As a result of adherence to generally accepted accounting principles, the tables above do not include the expected earnings impacts of certain non-derivative gas storage and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement.

The table below shows the maturity of our MTM positions:

														2011
(in Millions)														and				Total Fair
Source of Fair Value		2008				2009				2010				Beyond				Value
Proprietary Trading		$	20			$	33			$	—			$	—			$	53
Structured Contracts			(92	)			(124	)			(65	)			(126	)			(407	)
Economic Hedges			(4	)			6				(2	)			(3	)			(3	)
Other			(2	)			(4	)			(2	)			—				(8	)
Total		$	(78	)		$	(89	)		$	(69	)		$	(129	)		$	(365	)

Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

The Electric and Gas utility businesses have risks in connection with the anticipated purchases of coal, natural gas, uranium, electricity and base metals to meet their service obligations. Further, changes in the price of electricity can impact the level of exposure of Customer Choice programs and uncollectible expenses at the Electric Utility. In addition, changes in the price of natural gas can impact the valuation of lost gas, storage sales revenue and uncollectible expenses at the Gas Utility.

To limit our exposure to commodity price fluctuations, the utility businesses have applied various approaches including forward energy, capacity, storage and futures contracts, as well as regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms and a tracking mechanism to mitigate some losses from customer migration due to electric Customer Choice programs. See Note 6 of the Notes to Consolidated Financial Statements.

Our Power and Industrial Projects segment is subject to crude oil, electricity, natural gas and coal-based product price risk. To manage this exposure, we may use forward energy, capacity and futures contracts.

Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure, we use forward energy contracts and swaps.

Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil and foreign currency price fluctuations. These risks are managed through its energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.

Our Coal and Gas Midstream business segment has exposure to natural gas and coal price fluctuations. The coal price risks are managed primarily through its coal transportation and marketing operations through the use of forward coal and futures contracts. The Gas Midstream business unit manages its exposure through the sale of long-term storage and transportation contracts.

Credit Risk

Bankruptcies

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

Other

We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.

Energy Trading

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of March 31, 2008:

		Credit Exposure
		before Cash				Cash				Net Credit
(in Millions)		Collateral				Collateral				Exposure
Investment Grade (1)
A- and Greater		$	458			$	(84	)		$	374
BBB+ and BBB			107				—				107
BBB-			49				—				49
Total Investment Grade			614				(84	)			530
Non-investment grade (2)			99				(12	)			87
Internally Rated — investment grade (3)			149				—				149
Internally Rated — non-investment grade (4)			13				(8	)			5
Total		$	875			$	(104	)		$	771

Interest Rate Risk

We are subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of March 31, 2008, we had a floating rate debt-to-total debt ratio of approximately 8% (excluding securitized debt).

Foreign Currency Risk

We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through January 2013. Additionally, we may enter into fair value currency hedges to mitigate changes in the value of contracts or loans.

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at March 31, 2008 by a hypothetical 10% and calculating the resulting change in the fair values. The following represents the results of the sensitivity analysis calculations:

(in Millions)		Assuming a 10%				Assuming a 10%
Activity		increase in rates				decrease in rates				Change in the fair value of
Gas Contracts		$		(18)		$		21		Commodity contracts
Power Contracts		$		3		$		(3)		Commodity contracts
Interest Rate Risk		$		(283)		$		307		Long-term debt
Foreign Currency Risk		$	1			$		(1)		Forward contracts

Part I — Item 4.

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 the Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2008, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part I — Item 1.

DTE Energy Company

		Three Months Ended
		March 31
(in Millions, Except per Share Amounts)		2008				2007
Operating Revenues		$	2,570			$	2,463
Operating Expenses
Fuel, purchased power and gas			1,266				1,135
Operation and maintenance			699				734
Depreciation, depletion and amortization			226				224
Taxes other than income			80				90
Gain on sale of non-utility assets			(126	)			—
Other asset (gains) and losses, reserves and impairments, net			(4	)			10
			2,141				2,193
Operating Income			429				270
Other (Income) and Deductions
Interest expense			124				137
Interest income			(4	)			(6	)
Other income			(22	)			(18	)
Other expenses			14				9
			112				122
Income Before Income Taxes and Minority Interest			317				148
Income Tax Provision			116				51
Minority Interest			1				1
Income from Continuing Operations			200				96
Discontinued Operations
Income (loss) from discontinued operations, net of tax			12				(21	)
Minority interest in discontinued operations			—				(59	)
			12				38
Net Income		$	212			$	134
Basic Earnings per Common Share
Income from continuing operations		$	1.23			$	0.54
Discontinued operations			0.08				0.22
Total		$	1.31			$	0.76
Diluted Earnings per Common Share
Income from continuing operations		$	1.23			$	0.54
Discontinued operations			0.07				0.22
Total		$	1.30			$	0.76
Weighted Average Common Shares Outstanding
Basic			162				176
Diluted			163				177
Dividends Declared per Common Share		$	0.53			$	0.53

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

		March 31				December 31
(in Millions)		2008				2007
ASSETS
Current Assets
Cash and cash equivalents		$	77			$	123
Restricted cash			83				140
Accounts receivable (less allowance for doubtful accounts of $203 and $182, respectively)
Customer			1,719				1,658
Collateral held by others			66				53
Other			224				461
Accrued power and gas supply cost recovery revenue			40				76
Inventories
Fuel and gas			273				429
Materials and supplies			210				204
Deferred income taxes			167				387
Assets from risk management and trading activities			342				181
Other			158				196
Current assets held for sale			75				83
			3,434				3,991
Investments
Nuclear decommissioning trust funds			797				824
Other			437				446
			1,234				1,270
Property
Property, plant and equipment			19,003				18,809
Less accumulated depreciation and depletion			(7,511	)			(7,401	)
			11,492				11,408
Other Assets
Goodwill			2,037				2,037
Regulatory assets			2,776				2,786
Securitized regulatory assets			1,095				1,124
Intangible assets			30				25
Notes receivable			77				87
Assets from risk management and trading activities			259				199
Prepaid pension assets			156				152
Other			127				116
Noncurrent assets held for sale			431				547
			6,988				7,073
Total Assets		$	23,148			$	23,742

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)

		March 31				December 31
(in Millions, Except Shares)		2008				2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	1,015			$	1,189
Accrued interest			126				112
Dividends payable			86				87
Short-term borrowings			550				1,084
Gas inventory equalization			336				—
Current portion long-term debt, including capital leases			460				454
Liabilities from risk management and trading activities			451				281
Deferred gains and reserves			379				400
Other			451				566
Current liabilities associated with assets held for sale			48				48
			3,902				4,221
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other			5,320				5,576
Securitization bonds			996				1,065
Trust preferred-linked securities			289				289
Capital lease obligations			40				41
			6,645				6,971
Other Liabilities
Deferred income taxes			1,793				1,824
Regulatory liabilities			1,166				1,168
Asset retirement obligations			1,282				1,277
Unamortized investment tax credit			105				108
Liabilities from risk management and trading activities			515				450
Liabilities from transportation and storage contracts			122				126
Accrued pension liability			68				68
Accrued postretirement liability			1,055				1,094
Deferred gains			15				15
Nuclear decommissioning			130				134
Other			277				303
Noncurrent liabilities associated with assets held for sale			67				82
			6,595				6,649
Commitments and Contingencies (Notes 2, 6 and 9)
Minority Interest			41				48
Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 163,148,592 and 163,232,095 shares issued and outstanding, respectively			3,166				3,176
Retained earnings			2,920				2,790
Accumulated other comprehensive loss			(121	)			(113	)
			5,965				5,853
Total Liabilities and Shareholders’ Equity		$	23,148			$	23,742