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		Smaller reporting company o
				(Do not check if a smaller reporting company)

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 June 30, 2008, 163,095,193 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 June 30, 2008

TABLE OF CONTENTS

		Page
Definitions			1
Forward-Looking Statements			3
Part I – Financial Information
Item 1. Financial Statements
Consolidated Statements of Operations (Unaudited)			31
Consolidated Statements of Financial Position (Unaudited)			32
Consolidated Statements of Cash Flows (Unaudited)			34
Consolidated Statements of Changes in Shareholders’ Equity and Comprehensive Income (Unaudited)			35
Notes to Consolidated Financial Statements (Unaudited)			36
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			5
Item 3. Quantitative and Qualitative Disclosures About Market Risk			27
Item 4. Controls and Procedures			30
Part II – Other Information
Item 1. Legal Proceedings			60
Item 1A. Risk Factors			60
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			60
Item 4. Submission of Matters to a Vote of Security Holders			61
Item 5. Other Information			62
Item 6. Exhibits			62
Signature			63
EX-4.242
EX-4.243
EX-31.41
EX-31.42
EX-32.41
EX-32.42

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 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; and
	•		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.

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 second quarter of 2008 was $28 million, or $0.17 per diluted share, compared to net income of $385 million, or $2.20 per diluted share, in the second quarter of 2007. Net income for the six months ended June 30, 2008 was $240 million, or $1.48 per diluted share, compared to net income of $519 million, or $2.95 per diluted share, in the comparable period of 2007. The decreases were due primarily to $359 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $897 million ($569 million after-tax), partially offset by losses recognized on related hedges of $323 million ($210 million after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income during the second quarter of 2007. The comparison for the six-month period is also impacted by a 2008 gain of $128 million ($81 million after-tax) on the sale of a portion of the Barnett shale properties.

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 market demand on coal supply;
•		Challenges associated with nuclear fuel;
•		Discontinuance of planned monetization of our Power and Industrial Projects business;
•		Monetization of our Unconventional Gas Production 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 six months ended June 30, 2008, we experienced colder weather than in the six months ended June 30, 2007.

Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure, resulting in power outages. Restoration and other expenses associated with storm-related power outages were $31 million and $43 million in the three and six months ended June 30, 2008 as compared to $10 million and $29 million in the three and six months ended June 30, 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 $94 million for the 2008 quarter, in comparison to $39 million for the 2007 quarter. We experienced an increase in allowance for doubtful accounts expense to approximately $136 million during the six months ended June 30, 2008, in comparison to $68 million during the six months ended June 30, 2007.

The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. MichCon’s operating revenues include a component representing ninety percent of the difference between the actual uncollectible expense for each year and $37 million, including carrying charges. An annual reconciliation proceeding before the MPSC is held. 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. An MPSC order related to this filing is expected by early 2009. 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 $7 million and $25 million in the three and six months ended June 30, 2008, respectively, and approximately $17 million and $34 million in the three and six months ended June 30, 2007, respectively, 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 six months of 2008. In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the base gas to GCR customers during the 2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of the 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income, and not include the proceeds in the calculation of MichCon’s revenue requirements in future rate cases.

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 June 30, 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.
	•		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.

In June 2008, a package of bills to establish a sustainable, long-term energy plan was passed by the Michigan Senate. Key provisions of the bills passed by the Michigan Senate that differ from the package of bills passed by the Michigan House of Representatives in April 2008 include:

	•		A requirement that the MPSC set rates based on cost-of-service for all customer classes, eliminating the current subsidy for residential customers and certain business customers included in business customer rates. Elimination of the subsidy (de-skewing) would be phased in over a five year period for certain business customers and over a ten year period for residential customers.
	•		A combined renewable portfolio standard (RPS) and energy efficiency impacts of 2% by 2011, 4% by 2012, 6% by 2014 and 7% by 2015.

The next step in the process is the reconcilement of the bills passed by the Michigan House of Representatives and the Michigan Senate and approval of a final energy reform plan. Two House-Senate conference committees have been appointed to resolve differences in the energy package. We are unable to predict the timing and outcome of the legislative process and the impact of the legislative process on the Company.

Impact of Increased Market Demand on 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 which are passed to our customers through the PSCR. 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 various actions including the sale, restructuring or recapitalization of certain non-utility businesses.

Beginning in the second quarter of 2008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment to the Power and Industrial Projects segment due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. See Note 10 of the Notes to Consolidated Financial Statements for further information on this realignment.

Gas Midstream

Gas Midstream 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. In addition, pursuant to a separate agreement, MichCon provides physical operations, maintenance and technical support for a portion of the Vector Pipeline system which MichCon leases to Vector. Gas Midstream is continuing its steady growth plan with two new storage capacity 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 62,462 (60,634 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 – In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. 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 cumulative pre-tax gain of $128 million ($81 million after-tax) on the sale during 2008.

We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $60 million in the Barnett shale for the first six months of 2008 and expect to invest an additional $35 million to $40 million during the remainder of the year. During 2008, we expect to drill 30 to 35 new wells and achieve Barnett shale production of approximately 5 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, coal transportation and marketing 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. 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 two of these coke batteries generates production tax credits. The business provides coal transportation services including 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. This business performs 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 expanded our coal storage and blending capacity with the start of commercial operation of our coal terminal in Chicago in April 2007.

Discontinuance of Planned Monetization of our Power and Industrial Projects Business – During the third quarter of 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time. During the second quarter of 2008, the United States asset sale market has weakened and challenges in the debt market have persisted. Additionally, the performance of the portfolio of select Power and Industrial Projects has improved. As a result of these developments, our work on this planned monetization has been discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale.

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 for 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), subject to the MPSC establishing a recovery mechanism. 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 $2 million for the three months ended June 30, 2008 and 2007, respectively, and $8 million and $5 million for the six months ended June 30, 2008 and 2007, respectively. Detroit Edison deferred approximately $7 million and $8 million of CTA for the three months ended June 30, 2008 and 2007, respectively, and approximately $11 million and $21 million of CTA for the six months ended June 30, 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 second quarter of 2008 was $28 million, or $0.17 per diluted share, compared to net income of $385 million, or $2.20 per diluted share, in the second quarter of 2007. Net income for the six months ended June 30, 2008 was $240 million, or $1.48 per diluted share, compared to net income of $519 million, or $2.95 per diluted share, in the comparable period of 2007. The decreases were due primarily to $359 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $897 million ($569 million after-tax), partially offset by losses recognized in 2007 on related hedges of $323 million ($210 million after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income. The comparison for the six-month period is also impacted by a 2008 gain of $128 million ($81 million after-tax) on the sale of a portion of the Barnett shale properties.

Segments realigned – Beginning in the second quarter of 2008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment to the Power and Industrial Projects segment due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. See Note 10 of the Notes to Consolidated Financial Statements for further information on this realignment.

The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

Net income by segment for the three and six month periods ended June 30, 2008 and 2007 is as follows:

Gross margin decreased $50 million in the second quarter of 2008 and $39 million in the six-month period ended June 30, 2008. The decreases in 2008 were primarily due to the absence of the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and the unfavorable impacts of weather and service territory performance. The decreases were partially offset by higher rates attributable to the April 2008 expiration of a rate reduction related to the MPSC show cause proceeding and higher margins due to customers returning from the electric Customer Choice program. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. See Note 6 of the Notes to Consolidated Financial Statements.

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

Operation and maintenance expense decreased $11 million in the second quarter of 2008 and $1 million in the six-month period ended June 30, 2008. The decrease for the second quarter was primarily due to the absence of $27 million of 2007 Enterprise Business Systems (EBS) implementation costs, lower benefits expense of $12 million and $5 million attributable to continuous improvement initiatives, partially offset by higher storm expense of $21 million and higher uncollectible expenses of $19 million. The decrease in the six-month period was due primarily to the absence of $27 million of 2007 EBS implementation costs and lower benefit expenses of $18 million , partially offset by higher storm expense of $14 million, higher uncollectible expense of $29 million and higher labor and other expenses of $7 million.

Depreciation and amortization expense decreased $20 million in the second quarter of 2008 and $10 million in the six-month period ended June 30, 2008 due primarily to decreased amortization of regulatory assets.

Taxes other than income decreased $9 million in the second quarter of 2008 and $19 million in the six-month period ended June 30, 2008 due to the Michigan Single Business Tax (SBT) expense in 2007, which was replaced with the Michigan Business Tax (MBT) in 2008. The MBT is accounted for in the Income tax provision.

Other asset (gains), losses and reserves, net decreased $1 million in the second quarter of 2008 and decreased $6 million in the six-month period ended June 30, 2008 due to a $1 million gain on sale of an asset in the 2007 second quarter and a $7 million reserve established in the six-month 2007 period 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 and cash flow 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 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 and Michigan Senate, 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.

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 and corresponding impacts on demand for electricity;
	•		Collectibility of accounts receivable;
	•		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.

Gross margin increased $32 million in the second quarter of 2008 and $42 million in the six-month period ended June 30, 2008. The increase in the second quarter is due primarily to higher revenue of $33 million associated with the uncollectible tracking mechanism and $8 million of transportation revenue, partially offset by $4 million of lower storage services, $4 million as a result of customer conservation and lower volumes and $1 million due to the unfavorable impact of weather. The increase in the six-month period is due primarily to higher revenue associated with the uncollectible tracking mechanism of $33 million, the $9 million favorable impact of lower lost gas recognized, higher natural gas transportation revenue of $4 million and $2 million due to the favorable impact of weather, partially offset by $4 million as a result of customer conservation and lower volumes and $4 million of lower storage services. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.

Operation and maintenance expense increased $35 million in the second quarter of 2008 and $47 million in the six-month period ended June 30, 2008, primarily due to increases in uncollectible expenses of $37 million and $47 million, respectively. The increases in uncollectible expense are partially offset by increased revenues from the uncollectible tracking mechanism included in gross margin discussed above.

Depreciation and amortization expense increased $2 million in the second quarter of 2008 and $5 million in the six-month period ended June 30, 2008 due to higher levels of depreciable plant. In the six-month period ended June 30, 2007, we recorded a $3 million adjustment resulting from an MPSC order related to pipeline assets.

Other asset losses and reserves, net decreased $3 million in the six-month period ended June 30, 2008. In the six-month period ended June 30, 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 the timing of 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.

Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, Washington 28’s increased storage capacity of 1.8 Bcf was placed in service, increasing the total capacity 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 several months to a total capacity of 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. In addition, Vector Pipeline received FERC approval in June 2008 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. Both the 2007 and 2009 expansion projects are supported by customers under long-term contracts. Gas Midstream has a 26% ownership interest in Millennium Pipeline which commenced construction in June 2007 and is scheduled to be in service in late 2008. Millennium Pipeline currently has nearly 85% of its capacity sold to customers under long-term contracts.

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.

In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. 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 gain of $128 million ($81 million after-tax) on the sale in 2008.

Factors impacting income : The 2007 results reflect the recording of $323 million of losses on financial contracts related to expected Antrim gas production and sales through 2013. The 2008 six-month results include a gain of $128 million ($81 million after-tax) recognized on the sale of our Barnett shale property. In addition, lower gas sales volumes were offset by higher commodity prices and higher gas and oil production from retained wells in 2008 compared to 2007.

Operating revenues increased $300 million in the second quarter of 2008 and $282 million in the 2008 six-month period. The improvements reflect the recording of $323 million of losses during the 2007 periods on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions. In conjunction with the Antrim sale and effective settlement of these contract positions, Antrim reclassified amounts held in accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in the 2007 periods by $323 million. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $23 million and $41 million in the three and six months ended June 30, 2008 as compared to the same periods in 2007. The decreases were principally due to lower natural gas sales volumes as a result of our monetization initiatives, partially offset by higher commodity prices and higher gas and oil production on retained wells.

Operation and maintenance expense was lower by $9 million and $14 million in the second quarter and six-month period ended June 30, 2008, respectively, as a result of our monetization initiatives. For the six-month period ended June 30, 2008, Barnett shale production was approximately 2.2 Bcfe compared with approximately 3.4 Bcfe during the same period in 2007.

Outlook — We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $60 million in the Barnett shale for the first six months of 2008 and expect to invest an additional $35 million to $40 million during the remainder of the year. During 2008, we expect to drill 30 to 35 new wells and achieve Barnett shale production of approximately 5 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, biomass energy projects and coal transportation and marketing.

During the third quarter of 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second

quarter of 2008, the United States asset sale market has weakened and challenges in the debt market have persisted. Additionally, the performance of the portfolio of select Power and Industrial Projects has improved. As a result of these developments, our work on this planned monetization has been discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used.

Factors impacting income : We incurred a net loss of $6 million in the 2008 second quarter as compared to $9 million net income in 2007. Net income decreased $13 million in the six-month period ended June 30, 2008.

Operating revenues decreased $88 million in the second quarter of 2008 and $160 million in the six-month period ended June 30, 2008.

Operation and maintenance expense decreased $85 million in the second quarter of 2008 and $144 million in the six-month period ended June 30, 2008.

The decreases are primarily a result of reduced coal transportation volume, partially offset by an increase in coal trading activity, for which operating revenues and operation and maintenance expense are reported net.

Assets (gains) losses and reserves, net expense increased $17 million in the second quarter of 2008 and $13 million in the six-month period ended June 30, 2008. These losses are primarily attributable to a loss of approximately $19 million related to the valuation adjustment for the cumulative depreciation and amortization upon reclassification of certain project assets as held and used. Partially offsetting this loss were gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production.

Outlook — 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. We expect to see a negative impact on net income through the rest of 2008, since approximately $11 million of our annual 2007 coal transportation and marketing business net income was dependent upon our Synfuel operations that ceased operations at the end of 2007.

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 : Energy Trading’s 2008 second quarter net loss was $1 million greater than the 2007 second quarter net loss. Net income increased $29 million in the six-month period ended June 30, 2008.

Gross margin increased $11 million in the second quarter of 2008 and increased $62 million in the six-month period ended June 30, 2008.

The second quarter 2008 increase is due primarily to an increase in unrealized margins of $18 million, partially offset by lower realized margins of $8 million for the second quarter of 2008. The increase in unrealized margins consisted of $30 million of favorability due to the absence of mark-to-market losses in the second quarter of 2007 reflecting revisions of valuation estimates for natural gas contracts, $22 million of current year mark to market gains in our power portfolio, primarily in transmission optimization and $6 million in our oil trading portfolio due to timing related losses in 2007. This favorability is partially offset by $40 million mark to market losses largely in our gas storage strategies. The decrease in realized margins consisted of $13 million from our power strategies, partially offset by $5 million improvement in realized margins from our gas strategies.

The increase for the six-month period is due to higher unrealized margins of $39 million and higher realized margins of $22 million. The increase in unrealized margins include mark to market favorability of $36 million in our power strategies, due primarily to transmission optimization and $27 million in our gas trading strategies. Additionally, the absence of $30 million in mark-to-market losses in the second quarter of 2007 reflecting revisions of valuation estimates for natural gas contracts contributed to current year to date favorability. Partially offsetting this favorability is $54 million of current year mark to market losses predominately from our gas storage and transportation portfolios. Higher realized margins consisted of $42 million from our gas strategies, primarily gas storage, partially offset by $22 million from our power marketing and transmission optimization strategies.

Operation and maintenance expense increased $6 million in the second quarter of 2008 and $9 million in the six-month period ended June 30, 2008 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 include 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: Corporate & Other results were lower by $506 million in the second quarter of 2008 and $507 million in the 2008 six-month period, due primarily to the 2007 gain on the sale of the Antrim shale gas exploration and production business of approximately $897 million ($569 million after-tax), partially offset by effective income tax rate adjustments.

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 six-month period ended June 30, 2008.

Operating revenues decreased $262 million in the second quarter of 2008 and $522 million for the six-month period ended June 30, 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 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 $313 million in the second quarter of 2008 and $629 million in the six-month period ended June 30, 2008 due to the cessation of operations of our synfuel facilities at December 31,

2007. The 2008 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 decreased $42 million in the second quarter of 2008 and $62 million in the six-month period ended June 30, 2008 due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 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.

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 six months ended June 30, 2008 increased $537 million from the comparable 2007 period. The operating cash flow increase primarily reflects higher net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred taxes and gains on sales of assets) and cash held as collateral associated with trading counterparty transactions.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated from plant and equipment expenditures. Net cash used for investing activities was $452 million for the six months ended June 30, 2008, compared with cash from investing activities of $811 million in the same period in 2007. The 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 decreased $191 million during the six months ended June 30, 2008 compared to the same period in 2007, primarily due to the issuance of long-term debt and lower repurchases of common stock, partially offset by the repurchase of tax-exempt bonds and the repayment of short-term borrowings.

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 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 six months of 2008 from the sale of a portion of Barnett shale properties. Proceeds from the monetization activities were used to repurchase common stock and redeem outstanding debt. 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.

In July 2008, we experienced approximately $600 million of cash outflows related to synfuel partner refunds and the return of trading counterparty cash held as collateral.

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 and the fair value of assets held in trust to satisfy future obligations for nuclear decommissioning and pension plans will not be significantly affected by current conditions in the credit market.

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, published indexes 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.
	•		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. 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 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 six months ended June 30, 2008:

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 a significant portion 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 June 30, 2008. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

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 quoted market prices, 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:

Part I — Item 3.