FORM 10-K
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2008
 
Commission file number 1-11607
 
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.)
One Energy Plaza, Detroit, Michigan
(Address of principal executive offices)
  48226-1279
(Zip Code)
 
313-235-4000
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock, without par value
  New York Stock Exchange
7.8% Trust Preferred Securities*
  New York Stock Exchange
7.50% Trust Originated Preferred Securities**
  New York Stock Exchange
 
 * Issued by DTE Energy Trust I. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust I has funds available for payment of such distributions.
 
** Issued by DTE Energy Trust II. DTE Energy fully and unconditionally guarantees the payments of all amounts due on these securities to the extent DTE Energy Trust II has funds available for payment of such distributions.
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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
 
On June 30, 2008, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $6.9 billion (based on the New York Stock Exchange closing price on such date). There were 163,256,618 shares of common stock outstanding at January 31, 2009.
 
Certain information in DTE Energy Company’s definitive Proxy Statement for its 2009 Annual Meeting of Common Shareholders to be held April 30, 2009, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the Registrant’s fiscal year covered by this report on Form 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K.
 


 

 
DTE Energy Company
Annual Report on Form 10-K
Year Ended December 31, 2008

TABLE OF CONTENTS
 
                 
        PAGE
 
    2  
    4  
 
PART I
      Business, Risk Factors, Unresolved Staff Comments and Properties     6  
      Legal Proceedings     25  
      Submission of Matters to a Vote of Security Holders     26  
 
PART II
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     27  
      Selected Financial Data     29  
      Management’s Discussion And Analysis of Financial Condition and Results of Operations     29  
      Quantitative and Qualitative Disclosures About Market Risk     63  
      Financial Statements and Supplementary Data     67  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     144  
      Controls and Procedures     144  
      Other Information     144  
 
PART III
      Directors, Executive Officers and Corporate Governance     144  
      Executive Compensation     144  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     144  
      Certain Relationships and Related Transactions, and Director Independence     144  
      Principal Accountant Fees and Services     144  
 
PART IV
      Exhibits and Financial Statement Schedules     144  
    155  
 Ninth Supplemental Indenture, dated as of December 1, 2008
 Forty-second Supplemental Indenture, dated as of December 1, 2008
 DTE Energy Company Executive Supplemental Retirement Plan as Amended and Restated
 DTE Energy Company Supplemental Retirement Plan as Amended and Restated
 DTE Energy Company Supplemental Savings Plan as Amended and Restated
 DTE Energy Company Executive Compensation Plan as Amended and Restated
 DTE Energy Company Plan for Deferring the Payment of Directors' Fees as Amended and Restated
 DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors as Amended and Restated
 Computation of Ratio of Earnings to Fixed Charges
 Subsidiaries of the Company
 Consent of Deloitte & Touche LLP
 Chief Executive Officer Section 302 Form 10-K Certification of Periodic Report
 Chief Financial Officer Section 302 Form 10-K Certification of Periodic Report
 Chief Executive Officer Section 906 Form 10-K Certification of Periodic Report
 Chief Financial Officer Section 906 Form 10-K Certification of Periodic Report
 Twentieth Amendment to Master Trust


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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 Company) and 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
 
FASB Financial Accounting Standards Board
 
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 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 that are 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
 
Subsidiaries The direct and indirect subsidiaries of DTE Energy Company


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Synfuels The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are 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


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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:
 
  •  access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;
 
  •  instability in capital markets which could impact availability of short and long-term financing;
 
  •  potential for continued loss on cash equivalents and investments, including nuclear decommissioning and benefit plan assets;
 
  •  the length and severity of ongoing economic decline;
 
  •  the timing and extent of changes in interest rates;
 
  •  the level of borrowings;
 
  •  the availability, cost, coverage and terms of insurance and stability of insurance providers;
 
  •  changes in the economic and financial viability of our customers, suppliers, and trading counterparties, and the continued ability of such parties to perform their obligations to the Company;
 
  •  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 increasing costs of remediation and compliance, including actual and 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;
 
  •  changes in the cost and availability of coal and other raw materials, purchased power and natural gas;
 
  •  the effects of competition;
 
  •  the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty;
 
  •  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 cost of protecting assets against, or damage due to, terrorism;
 
  •  changes in and application of accounting standards and financial reporting regulations;


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  •  changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues;
 
  •  amounts of uncollectible accounts receivable; and
 
  •  binding arbitration, litigation and related appeals.
 
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.


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Part I
 
Items 1. and 2. Business and Properties
 
General
 
In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of Detroit Edison and MichCon. We also have four non-utility segments that are engaged in a variety of energy-related businesses.
 
Detroit Edison is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the MPSC and the FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.
 
MichCon is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan.
 
Our four non-utility segments are involved in 1) gas pipelines and storage; 2) unconventional gas exploration, development, and production; 3) power and industrial projects and coal transportation and marketing; and 4) energy marketing and trading operations.
 
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and all amendments to such reports are available free of charge through the Investor Relations page of our website: www.dteenergy.com, as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission (SEC). Our previously filed reports and statements are also available at the SEC’s website: www.sec.gov.
 
The Company’s Code of Ethics and Standards of Behavior, Board of Directors Mission and Guidelines, Board Committee Charters, and Categorical Standards of Director Independence are also posted on its website. The information on the Company’s website is not part of this or any other report that the Company files with, or furnishes to, the SEC.
 
Additionally, the public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.
 
References in this Report to “we,” “us,” “our,” “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
 
Corporate Structure
 
Based on the following structure, we set strategic goals, allocate resources, and evaluate performance. See Note 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report for financial information by segment for the last three years.
 
Electric Utility
 
  •  Consists of Detroit Edison, our electric utility whose operations include the power generation and electric distribution facilities that service approximately 2.2 million residential, commercial, industrial and wholesale customers throughout southeastern Michigan.
 
Gas Utility
 
  •  Consists of the gas distribution services provided by MichCon, a gas utility that purchases, stores, transports and distributes natural gas throughout Michigan to approximately 1.2 million residential,


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  commercial and industrial customers, and Citizens Gas Fuel Company (Citizens), a gas utility that distributes natural gas in Adrian, Michigan to approximately 17,000 customers.
 
Non-Utility Operations
 
  •  Gas Midstream, primarily consisting of natural gas pipelines and storage;
 
  •  Unconventional Gas Production, primarily consisting of unconventional gas exploration, development and production;
 
  •  Power and Industrial Projects, primarily consisting of on-site energy services, steel-related projects, power generation and coal transportation and marketing; and
 
  •  Energy Trading, primarily consisting of energy marketing and trading operations.
 
Corporate & Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.
 
(ORGANIZATIONAL CHART)
 
Refer to our Management’s Discussion and Analysis in Item 7 of this Report for an in-depth analysis of each segment’s financial results. A description of each business unit follows.
 
ELECTRIC UTILITY
 
Description
 
Our Electric Utility segment consists of Detroit Edison. Our generating plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our several fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers. The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial, and wholesale, principally throughout southeastern Michigan.


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Revenue by Service
 
                         
    2008     2007     2006  
    (In millions)  
 
Residential
  $ 1,726     $ 1,739     $ 1,671  
Commercial
    1,753       1,723       1,603  
Industrial
    894       854       835  
Wholesale
    119       125       109  
Other
    170       259       350  
                         
Subtotal
    4,662       4,700       4,568  
Interconnection sales(1)
    212       200       169  
                         
Total Revenue
  $ 4,874     $ 4,900     $ 4,737  
                         
 
 
(1) Represents power that is not distributed by Detroit Edison.
 
Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands. We occasionally 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 can negatively impact earnings. In the December 23, 2008 MPSC rate order for Detroit Edison, a tracking mechanism was approved that provides for an annual reconciliation for restoration costs (storm and non-storm) using a base expense level of $110 million per year. Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.
 
Fuel Supply and Purchased Power
 
Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have eight long-term and two short-term contracts for a total purchase of approximately 26 million tons of low-sulfur western coal to be delivered in 2009 and 2010. We also have eight contracts for the purchase of approximately 6 million tons of Appalachian coal to be delivered from 2009 through 2011. All of these contracts have fixed prices. We have approximately 84% of our 2009 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.
 
Detroit Edison participates in the energy market through MISO. We offer our generation in the market on a day-ahead and real-time basis and bid for power in the market to serve our load. We are a net purchaser of power that supplements our generation capability to meet customer demand during peak cycles.
 
Properties
 
Detroit Edison owns generating plants and facilities that are located in the State of Michigan. Substantially all of our property is subject to the lien of a mortgage.


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Generating plants owned and in service as of December 31, 2008 are as follows:
 
                         
    Location by
  Summer Net
   
    Michigan
  Rated Capability(1)(2)    
Plant Name
  County   (MW)    (%)   Year in Service
 
Fossil-fueled Steam-Electric
                       
Belle River(3)
  St. Clair     1,026       9.2     1984 and 1985
Conners Creek
  Wayne     230       2.1     1951
Greenwood
  St. Clair     785       7.1     1979
Harbor Beach
  Huron     103       0.9     1968
Marysville
  St. Clair     84       0.8     1943 and 1947
Monroe(4)
  Monroe     3,115       28.0     1971, 1973 and 1974
River Rouge
  Wayne     523       4.7     1957 and 1958
St. Clair
  St. Clair     1,368       12.3     1953, 1954, 1959, 1961 and 1969
Trenton Channel
  Wayne     730       6.6     1949 and 1968
                         
          7,964       71.7      
Oil or Gas-fueled Peaking Units
  Various     1,101       9.9     1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2(5)
  Monroe     1,122       10.1     1988
Hydroelectric Pumped Storage Ludington(6)
  Mason     917       8.3     1973
                         
          11,104       100.0      
                         
 
 
(1) Summer net rated capabilities of generating plants in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation.
 
(2) Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW) in cold standby status.
 
(3) The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
(4) The Monroe Power Plant provided 38% of Detroit Edison’s total 2008 power plant generation.
 
(5) Fermi 2 has a design electrical rating (net) of 1,150 MW.
 
(6) Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
Detroit Edison owns and operates 678 distribution substations with a capacity of approximately 33,436,000 kilovolt-amperes (kVA) and approximately 419,600 line transformers with a capacity of approximately 21,634,000 kVA.


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Circuit miles of distribution lines owned and in service as of December 31, 2008:
 
Electric Distribution
 
                 
    Circuit Miles
Operating Voltage-Kilovolts (kV)
  Overhead   Underground
 
4.8 kV to 13.2 kV
    28,114       13,875  
24 kV
    102       690  
40 kV
    2,324       335  
120 kV
    72       13  
                 
      30,612       14,913  
                 
 
There are numerous interconnections that allow the interchange of electricity between Detroit Edison and electricity providers external to our service area. These interconnections are generally owned and operated by ITC Transmission and connect to neighboring energy companies.
 
Regulation
 
Detroit Edison’s business is subject to the regulatory jurisdiction of various agencies, including, but not limited to, the MPSC, the FERC and the NRC. The MPSC issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. The FERC regulates Detroit Edison with respect to financing authorization and wholesale electric activities. The NRC has regulatory jurisdiction over all phases of the operation, construction, licensing and decommissioning of Detroit Edison’s nuclear plant operations. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
 
See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Energy Assistance Programs
 
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to Detroit Edison’s ability to control its uncollectible accounts receivable and collections expenses. Detroit Edison’s uncollectible accounts receivable expense is directly affected by the level of government-funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.
 
Strategy and Competition
 
We strive to be the preferred supplier of electrical generation in southeast Michigan. We can accomplish this goal by working with our customers, communities and regulatory agencies to be a reliable, low-cost supplier of electricity. To ensure generation reliability, we continue to invest in our generating plants, which will improve both plant availability and operating efficiencies. We also are making capital investments in areas that have a positive impact on reliability and environmental compliance with the goal of high customer satisfaction.
 
Our distribution operations focus on improving reliability, restoration time and the quality of customer service. We seek to lower our operating costs by improving operating efficiencies. Revenues from year to year will vary due to weather conditions, economic factors, regulatory events and other risk factors as discussed in the “Risk Factors” in Item 1A. of this Report.
 
The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services. Customers choosing to purchase power from alternative electric suppliers represented approximately 3% of retail sales in 2008, 4% in 2007 and 6% of


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such sales in 2006. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed their cost of service. MPSC rate orders and recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a 10 percent cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer Choice on our financial performance. Recent higher wholesale electric prices have also resulted in many former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. When market conditions are favorable, we sell power into the wholesale market, in order to lower costs to full-service customers.
 
Competition in the regulated electric distribution business is primarily from the on-site generation of industrial customers and from distributed generation applications by industrial and commercial customers. We do not expect significant competition for distribution to any group of customers in the near term. In 2008, the Michigan legislature passed a comprehensive reform package that requires Michigan utilities to serve ten percent of their retail sales from renewable energy sources by 2015. In December 2008, Detroit Edison issued a request for proposal to purchase Michigan-based renewable energy credits.
 
GAS UTILITY
 
Description
 
Our Gas Utility segment consists of MichCon and Citizens.
 
Revenue is generated by providing the following major classes of service: gas sales, end user transportation, intermediate transportation, and gas storage.
 
Revenue by Service
 
                         
    2008     2007     2006  
    (In millions)  
 
Gas sales
  $ 1,824     $ 1,536     $ 1,541  
End user transportation
    143       140       135  
Intermediate transportation
    73       59       69  
Storage and other
    112       140       104  
                         
Total Revenue
  $ 2,152     $ 1,875     $ 1,849  
                         
 
  •  Gas sales — Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers.
 
  •  End user transportation — Gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our Customer Choice program. End user transportation customers purchase natural gas directly from producers or brokers and utilize our pipeline network to transport the gas to their facilities or homes.
 
  •  Intermediate transportation — Gas delivery service provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers utilize our gathering and high-pressure transmission system to transport the gas to storage fields, processing plants, pipeline interconnections or other locations.
 
  •  Storage and other — Includes revenues from gas storage, appliance maintenance, facility development and other energy-related services.
 
Our gas sales, end user transportation and intermediate transportation volumes, revenues and net income are impacted by weather. Given the seasonal nature of our business, revenues and net income are concentrated in the first and fourth quarters of the calendar year. By the end of the first quarter, the heating season is


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largely over, and we typically realize substantially reduced revenues and earnings in the second quarter and losses in the third quarter.
 
Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on our Gas Utility segment.
 
Natural Gas Supply
 
Our gas distribution system has a planned maximum daily send-out capacity of 2.8 Bcf, with approximately 68% of the volume coming from underground storage for 2008. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased gas supplies. Because of our geographic diversity of supply and our pipeline transportation and storage capacity, we are able to reliably meet our supply requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
 
We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to NYMEX and published price indices to approximate current market prices.
 
Properties
 
We own distribution, transmission and storage properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately 1,181,000 service lines and approximately 1,324,000 active meters. We own approximately 2,000 miles of transmission lines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas. We also own four carbon dioxide processing facilities.
 
We own properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 132 Bcf. These facilities are important in providing reliable and cost-effective service to our customers. In addition, we sell storage services to third parties. Most of our distribution and transmission property is located on property owned by others and used by us through easements, permits or licenses. Substantially all of our property is subject to the lien of a mortgage.
 
We are directly connected to interstate pipelines, providing access to most of the major natural gas producing regions in the Gulf Coast, Mid-Continent and Canadian regions.
 
Our primary long-term transportation contracts are as follows:
 
                 
    Availability (MMcf/d)   Contract Expiration
 
Trunkline Gas Company
    10       2009  
Viking Gas Transmission Company
    51       2010  
TransCanada PipeLines Limited
    53       2010  
Great Lakes Gas Transmission L.P. 
    30       2011  
ANR Pipeline Company
    245       2011  
Vector Pipeline L.P. 
    50       2012  
Panhandle Eastern Pipeline Company
    75       2029  
 
We own 830 miles of transportation and gathering (non-utility) pipelines in the northern lower peninsula of Michigan. Our Hawes pipeline project is currently under construction and will add an additional 10 miles of pipeline when completed in early 2009. We lease a portion of our pipeline system to the Vector Pipeline Partnership (an affiliate) through a capital-lease arrangement. See Note 14 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


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Regulation
 
We are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and operating-related matters. MichCon’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
 
See Note 5 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
Energy Assistance Program
 
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to MichCon’s ability to control its uncollectible accounts receivable and collections expenses. MichCon’s uncollectible accounts receivable expense is directly affected by the level of government-funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.
 
Strategy and Competition
 
Our strategy is to be the preferred provider of natural gas in Michigan. As a result of more efficient furnaces and appliances, and customer conservation due to high natural gas prices and economic conditions, we expect future sales volumes to decline. We continue to provide energy-related services that capitalize on our expertise, capabilities and efficient systems. We continue to focus on lowering our operating costs by improving operating efficiencies.
 
Competition in the gas business primarily involves other natural gas providers, as well as providers of alternative fuels and energy sources. The primary focus of competition for end user transportation is cost and reliability. Some large commercial and industrial customers have the ability to switch to alternative fuel sources such as coal, electricity, oil and steam. If these customers were to choose an alternative fuel source, they would not have a need for our end-user transportation service. In addition, some of these customers could bypass our pipeline system and have their gas delivered directly from an interstate pipeline. We compete against alternative fuel sources by providing competitive pricing and reliable service, supported by our storage capacity.
 
Our extensive transmission pipeline system has enabled us to market 400 to 500 Bcf annually for intermediate transportation services and storage services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a central geographic location with connections to major Mid-western interstate pipelines that extend throughout the Midwest, eastern United States and eastern Canada.
 
MichCon’s storage capacity is used to store natural gas for delivery to MichCon’s customers as well as sold to third parties, under a variety of arrangements for periods up to three years. Prices for storage arrangements for shorter periods are generally higher, but more volatile than for longer periods. Prices are influenced primarily by market conditions and natural gas pricing.
 
NON-UTILITY OPERATIONS
 
Gas Midstream
 
Description
 
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 long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We also hold partnership interests in Millennium Pipeline Company which indirectly connects southern New York State to Upper Midwest/Canadian supply, while


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providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 87 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facilities are high deliverability storage fields having bi-directional interconnections with Vector Pipeline and MichCon providing our customers access to the Chicago, Michigan, other Midwest and Ontario market centers.
 
Our customers include various utilities, pipelines, and producers and marketers.
 
Properties
 
The Gas Midstream business holds the following property:
 
                 
Property Classification
  % Owned     Description   Location
 
Pipelines
               
Vector Pipeline
    40%     348-mile pipeline with 1,200 MMcf per day capacity   Midwest
Millennium Pipeline (in service December 2008)
    26%     182-mile pipeline with 525 MMcf per day capacity   New York
Storage
               
Washington 10 (includes Shelby 2 Storage)
    100%     71 Bcf of storage capacity   Macomb Co, MI
Washington 28
    50%     16 Bcf of storage capacity   Macomb Co, MI
 
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 the Washington 28 and Washington 10 storage facilities.
 
Strategy and Competition
 
Our Gas Midstream business expects to continue its steady growth plan. The Gas Midstream business focuses on asset development opportunities in the Midwest-to-Northeast region to supply natural gas to meet growing demand. We expect much of the growth in the demand for natural gas in the U.S. to occur within the Mid-Atlantic and New England regions. We forecast these regions will require incremental pipeline and gas storage infrastructure necessary to deliver gas volumes to meet growing demand. Vector is an interstate pipeline that is filling a large portion of that need, and is complemented by our Michigan storage facilities. We will complete the Shelby 2 storage field at our Washington 10 storage complex by 2010 with an additional 3 Bcf of capacity additions. Once completed the combined capacity for Washington 10 and Washington 28 will be approximately 90 Bcf. Vector Pipeline received FERC approval in June 2008 to build an additional compressor station in Michigan and to expand the Vector Pipeline by approximately 100 MMcf/d to 1.3 Bcf/d, with a proposed in-service date of November 1, 2009. Gas Midstream has a 26 percent ownership interest in Millennium Pipeline which is capable of transporting 525,000 dth/d of natural gas across the southern tier of New York towards New York City. Millennium was placed in-service December 2008. We plan to expand existing assets and develop new assets that are typically supported with long-term customer commitments.
 
Unconventional Gas Production
 
Description
 
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in north Texas. In June 2007, we sold our Antrim shale gas exploration and production business in the northern lower peninsula of Michigan for gross proceeds of $1.262 billion. In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties in the 2008 sale include 75 Bcfe of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale.


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In 2008, we added proved reserves of 23 Bcfe in the Barnett shale resulting in year-end total proved reserves of 167 Bcfe. The Barnett shale wells yielded 5 Bcfe of production in 2008. Barnett shale leasehold acres increased to 62,395 gross acres (60,435 net of interest of others) excluding impairments. We drilled a total of 37 wells in the Barnett shale acreage.
 
Our Barnett Shale gas production requires processing to extract natural gas liquids. Therefore, our wells are dedicated to various gathering and processing companies in the Fort Worth Basin. The revenues received for all products are sold at prevailing market based prices.
 
Properties
 
Unconventional Gas Production owns interests in the following producing wells and acreage in the Barnett shale as of December 31:
 
                                                 
    2008   2007   2006
    Gross   Net(1)   Gross   Net(1)   Gross   Net(1)
 
Producing Wells (2)
                                               
Barnett shale(3)
    156       155       120       120       83       83  
Held for sale
                53       33       41       27  
                                                 
      156       155       173       153       124       110  
                                                 
Developed Lease Acreage (4)
                                               
Barnett shale(3)
    14,322       14,248       9,922       9,880       10,759       10,693  
Held for sale
                7,379       4,987       5,679       3,977  
                                                 
      14,322       14,248       17,301       14,867       16,438       14,670  
                                                 
Undeveloped Lease Acreage (5)
                                               
Barnett shale(3)
    48,073       46,187       38,793       38,066       30,649       27,613  
Held for sale
                7,447       5,809       7,073       6,164  
                                                 
      48,073       46,187       46,240       43,875       37,722       33,777  
                                                 
 
 
(1) Excludes the interest of others.
 
(2) Producing wells are the number of wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
 
(3) Excludes sold and impaired properties.
 
(4) Developed lease acreage is the number of acres that are allocated or assignable to productive wells or wells capable of production.
 
(5) Undeveloped lease acreage is the number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
 
Strategy and Competition
 
We manage and operate our Barnett shale gas properties to maximize returns on investment and increase earnings with the overriding goal of optimizing the cost of producing reserves and adding additional proved reserves. We will consider potential periodic monetizations where market conditions are appropriate.


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From time to time, we use financial derivative contracts to manage a portion of our exposure to changes in the price of natural gas on our forecasted natural gas sales. The following is a summary of the financial contracts in place at December 31, 2008 related to Barnett shale production:
 
                 
    2009   2010
 
Long-term fixed price obligations
               
Volume- Bcf
    2.0       1.2  
Price- $/Mcf
  $ 7.42     $ 7.16  
 
We continue to invest in 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. Current economic conditions and depressed commodity prices have created challenges and opportunities in the Barnett shale. While operating margins are expected to be lower than 2008, opportunities exist to reduce operating, drilling and completion costs primarily due to the increased availability of drilling rigs and oil field service companies.
 
In 2009, we expect to drill approximately 15 to 25 wells in the Barnett shale. Investment for the area is expected to be approximately $25 million during 2009.
 
Power and Industrial Projects
 
Description
 
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type services to steel, automotive and other industrial, commercial and institutional customers; provide coal transportation and marketing; and develop biomass energy projects. This business segment 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.
 
These services include pulverized coal, petroleum coke and metallurgical 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, two biomass-fired electric generating plants and operate one coal-fired power plant under contract. A third biomass-fired electric generating plant is currently under development pending certain regulatory and management approvals with an expected in-service date of January 2010. Production tax credits related to two of the coke battery facilities were reinstated for the years 2006 through 2009. The coke battery facilities produce coke that is used in blast furnaces within the steel industry. Detroit Edison provides operations and maintenance services for the pulverized coal facility located at Detroit Edison’s River Rouge power plant.
 
We also provide coal transportation services including fuel, transportation, storage, blending and rail equipment management services. Our external customers include electric utilities, merchant power producers, integrated steel mills and large industrial companies with significant energy requirements. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. We own and operate a coal transloading terminal in South Chicago, Illinois.
 
We develop, own and operate landfill gas recovery systems throughout the United States. Landfill gas, a byproduct of solid waste decomposition, is composed of approximately equal portions of methane and carbon dioxide. We develop landfill gas recovery systems that capture the gas and provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy, in addition to providing environmental benefits by reducing greenhouse gas emissions. This business segment 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 own a coal mine methane gathering system and gas processing facility.
 
Discontinuance of Planned Monetization of a Portion 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. During 2008, the United States asset sale market weakened and challenges in


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the debt market persisted. As a result of these developments, our work on this planned monetization was discontinued.
 
Properties
 
The following are significant properties operated by the Power and Industrial projects segment:
 
                 
Facility
  Location   % Owned   Service Type
 
Steel
               
DTE PCI Enterprises Company
  River Rouge, MI     100%     Pulverized Coal
DTE Sparrows Point
  Sparrows Point, MD     100%     Pulverized Coal
EES Coke Battery
  River Rouge, MI     100%     Metallurgical Coke Supply
DTE Shenango
  Pittsburgh, PA     100%     Metallurgical Coke Supply
Indiana Harbor Coke Co.,
  East Chicago, IN     14.8%     Metallurgical Coke Supply
Automotive
               
DTE Energy Center
  Various sites in     50%     Electric Distribution, Chilled
    MI, IN, OH           Water, Waste Water, Compressed Air, Mist and Dust Collectors
DTE Northwind
  Detroit, MI     100%     Steam and Chilled Water
DTE Moraine
  Moraine, OH     100%     Compressed Air
DTE Tonawanda
  Tonawanda, NY     100%     Chilled and Waste Water
DTE Defiance
  Defiance, OH     100%     Steam, Cooling Tower Water, Chilled Water, Compressed Air
DTE Heritage
  Dearborn, MI     100%     Electric Distribution
DTE Dearborn
  Dearborn, MI     100%     Steam, Chilled Water, Compressed Air, Waste Water
DTE Pontiac North
  Pontiac, MI     100%     Electric Generation and Steam
DTE Lordstown
  Lordstown, OH     100%     Steam, Chilled Water, Compressed Air, and Reverse Osmosis Water
Pulp and Paper
               
Mobile Energy Services
  Mobile, AL     50%     Electric Generation and Steam
Airport
               
Metro Energy
  Romulus, MI     100%     Electricity, Hot and Chilled Water
DTE Pittsburgh
  Pittsburgh, PA     100%     Hot and Chilled Water
Other Industries
               
DTE PetCoke
  Vicksburg, MS     100%     Pulverized Petroleum Coke
Power Generation
               
DTE East China (320MW)
  East China Twp, MI     100%     Natural Gas Generating Plant
Woodland Biomass (25MW)
  Woodland, CA     99%     Wood Fired Power Plant
DTE Stoneman (40MW)
  Cassville, WI     100%     Biomass Power Plant
Coal Transportation and Marketing
               
DTE Chicago Fuels Terminal
  Chicago, IL     100%     Coal Terminal and Blending Plant


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Landfill Gas Recovery
 
                         
    2008   2007   2006
 
Landfill Sites
    23       28       26  
Gas Produced (in Bcf)
    18.6       23.5       22.9  
 
Coal Transportation and Marketing
 
                         
    2008   2007   2006
    (In millions)
 
Tons of Coal Shipped(1)
    18       35       34  
 
 
(1) Includes intercompany transactions of 2 million, 19 million, and 14 million tons in 2008, 2007, and 2006, respectively, primarily related to synfuel operations in 2007 and 2006.
 
                                 
Production Tax Credits Generated (Allocated to DTE Energy)
  2008   2007   2006    
    (In millions)    
 
Coke Battery
  $ 5     $ 5     $ 6          
Power Generation
    2       2       1          
Landfill Gas Recovery
          3       5          
 
Strategy and Competition
 
Power and Industrial Projects will continue leveraging its energy-related operating experience and project management capability to develop and grow our steel; renewable power; on-site energy; coal transportation, marketing, storage and blending; and landfill gas recovery businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties.
 
We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we examine closely the regulatory and competitive environment, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue growth opportunities, our first priority will be to achieve value-added returns.
 
We intend to focus on the following areas for growth:
 
  •  Providing operating services to owners of industrial and power plants; and
 
  •  Acquiring and developing solid fuel-fired power plants, landfill gas recovery facilities, renewable energy projects, and other energy projects qualifying for tax credits.
 
Due to a weakened U.S. economy including constricted capital and credit markets, we expect significantly lower demand for steel in 2009 impacting the financial performance of our coke battery and pulverized coal operations. In addition, the automotive sector has been severely impacted by the current economic situation and has resulted in curtailment of production and plant closings. We will continue to monitor the steel and automotive industries closely during 2009.
 
Our Coal Transportation and Marketing business is one of the leading North American coal marketers. Trends such as railroad and mining consolidation and the lack of certainty in developing new mines by many mining firms could have an impact on how we compete in the future. In 2011, our existing long-term rail transportation contract which gives us a competitive advantage will expire. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers. We will seek to build our capacity to transport, store and blend greater amounts of coal and expect to continue to grow our business in a manner consistent with, and complementary to, the growth of our other business segments.


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Energy Trading
 
Description
 
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 pipeline transportation 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. 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.
 
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, however 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 gains or losses in one period that could reverse in subsequent periods.
 
Strategy and Competition
 
Our strategy for the energy trading business is to deliver value-added services to our customers. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We focus on physical marketing and the optimization of our portfolio of energy assets. We compete with electric and gas marketers, traders, utilities and other energy providers. The trading business is dependent upon the availability of capital and an investment grade credit rating. A material credit restriction would negatively impact our financial performance. Competitors with greater access to capital or at a lower cost may have a competitive advantage. We have risk management and credit processes to monitor and mitigate risk.
 
CORPORATE & OTHER
 
Description
 
Corporate & Other includes various holding company activities and holds certain non-utility debt and energy-related investments.
 
DISCONTINUED OPERATIONS
 
Synthetic Fuel
 
Description
 
The Synthetic Fuel business was presented as a non-utility segment through the third quarter of 2007. 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 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. To optimize income and cash flow from the synfuel operations, we sold interests in all nine of the facilities, representing 91% of the total production capacity. The synthetic fuel plants generated operating losses that were offset by production tax credits.


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The value of a production tax credit was adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value of production tax credits for synthetic fuel was reduced when the Reference Price of a barrel of oil exceeded certain thresholds.
 
                 
    2007     2006  
    (In millions)  
 
Production Tax Credits Generated
               
Allocated to DTE Energy
  $ 21     $ 23  
Allocated to partners
    186       260  
                 
    $ 207     $ 283  
                 
 
ENVIRONMENTAL MATTERS
 
We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers. The following table summarizes our estimated significant future environmental expenditures based upon current regulations:
 
                                 
    Electric     Gas     Non-Utility     Total  
    (In millions)  
 
Air
  $ 2,800     $     $     $ 2,800  
Water
    55             1       53  
MGP sites
    3       38             41  
Other sites
    9       1             10  
                                 
Estimated total future expenditures through 2018
  $ 2,867     $ 39     $ 1     $ 2,904  
                                 
Estimated 2009 expenditures
  $ 100     $ 3     $ 1     $ 104  
                                 
 
Air — Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions.
 
Water — In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of studies to be conducted over the next several years, Detroit Edison may be required to perform some mitigation activities, including the possible installation of additional control technologies to reduce the environmental impact of the intake structures. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation, resulting in a delay in complying with the regulation. In 2008, the U.S. Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule. A decision is expected in the first quarter of 2009. Concurrently, the EPA continues to develop a revised rule, which is expected to be published in early 2009.
 
Manufactured Gas Plant (MGP) and Other Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas for heating and other uses, have been designated as MGP sites. Gas Utility owns, or previously owned, fifteen such former MGP sites. In addition to the MGP sites, we are also in the process of cleaning up other contaminated sites. Detroit Edison conducted remedial investigations at contaminated sites, including three MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. As a result of these determinations, we have recorded liabilities related to these sites. Cleanup activities associated with these sites will be conducted over the next several years.


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Non-utility — Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We are in the process of installing new environmental equipment at our coke battery facility in Michigan. We expect the project to be completed in the first half of 2009. Our non-utility affiliates are substantially in compliance with all environmental requirements.
 
Global Climate Change — Proposals for voluntary initiatives and mandatory controls are being discussed in the United States to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. There may be legislative and or regulatory action to address the issue of changes in climate that may result from the build up of greenhouse gases, including carbon dioxide, in the atmosphere. We cannot predict the impact any legislative or regulatory action may have on our operations and financial position.
 
See Notes 5 and 17 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
EMPLOYEES
 
We had 10,471 employees as of December 31, 2008, of which 5,331 were represented by unions. The majority of our union employees are under contracts that expire in June and October 2010 and August 2012.
 
EXECUTIVE OFFICERS OF DTE ENERGY
                 
            Present
            Position
Name
 
Age(1)
 
Present Position
 
Held Since
 
Anthony F. Earley, Jr. 
    59     Chairman of the Board and Chief Executive Officer   8-1-98
Gerard M. Anderson(2)
    50     Chief Operating Officer and   10-31-05
            President   6-23-04
David E. Meador(2)
    51     Executive Vice President and Chief Financial Officer   6-23-04
Lynne Ellyn
    57     Senior Vice President and Chief Information Officer   12-31-01
Paul C. Hillegonds(3)
    59     Senior Vice President   5-16-05
Steve E. Kurmas(2)
    52     President and Chief Operating Officer, Detroit Edison   12-08-08
            and Group President, DTE Energy   12-08-08
Bruce D. Peterson
    52     Senior Vice President and General Counsel   6-25-02
Gerardo Norcia(2)
    45     President and Chief Operating Officer, MichCon and   6-28-07
            Group President, DTE Energy   6-28-07
Larry E. Steward
    56     Vice President   1-15-01
Peter B. Oleksiak(2)
    42     Vice President and Controller   2-07-07
Sandra K. Ennis(2)
    52     Corporate Secretary   8-4-05
 
 
(1) As of December 31, 2008.
 
(2) These executive officers held various positions at DTE Energy for at least five or more years.
 
(3) For eight years prior to joining DTE Energy, Mr. Hillegonds was president of Detroit Renaissance, a private, non-profit executive leadership organization dedicated to the growth of the southeast Michigan economy.
 
Under our Bylaws, the officers of DTE Energy are elected annually by the Board of Directors at a meeting held for such purpose, each to serve until the next annual meeting of directors or until their respective successors are chosen and qualified.
 
Pursuant to Article VI of our Articles of Incorporation, directors of DTE Energy will not be personally liable to us or our shareholders in the performance of their duties to the full extent permitted by law.


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Article VII of our Articles of Incorporation provides that each current or former director or officer of DTE Energy, or each current and former employee or agent of the Company or a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (including the heirs, executors, administrators or estate of such person), shall be indemnified by us to the full extent permitted by the Michigan Business Corporation Act or any other applicable laws as presently or hereafter in effect. In addition, we have entered into indemnification agreements with all of our officers and directors; these agreements set forth procedures for claims for indemnification as well as contractually obligating us to provide indemnification to the maximum extent permitted by law.
 
We and our directors and officers in their capacities as such are insured against liability for alleged wrongful acts (to the extent defined) under eight insurance policies providing aggregate coverage in the amount of $185 million.
 
Item 1A.   Risk Factors
 
There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we are providing a brief explanation of the more significant risks associated with our businesses. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.
 
Regional and national economic conditions can have an unfavorable impact on us.  Our utility and non-utility businesses follow the economic cycles of the customers we serve. Our utilities and certain non-utility businesses provide services to the domestic automotive industry which is under considerable financial distress, exacerbating the decline in regional economic conditions. Should national or regional economic conditions further decline, reduced volumes of electricity and gas, and demand for energy services we supply, collections of accounts receivable and potentially higher levels of lost or stolen gas will result in decreased earnings and cash flow.
 
Adverse changes in our credit ratings may negatively affect us.  Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets and could result in an increase in our borrowing costs, a reduced level of capital expenditures and could impact future earnings and cash flows. In addition, a reduction in credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which would impact our liquidity.
 
Our ability to access capital markets at attractive interest rates is important.  Our ability to access capital markets is important to operate our businesses. In recent months, the global financial markets have experienced unprecedented instability. This systemic marketplace distress is impacting our access to capital and cost of capital. This recent turmoil in credit markets has constrained, and may again in the future constrain, our ability as well as the ability of our subsidiaries to issue new debt, including commercial paper, and refinance existing debt. We cannot predict the length of time the current worldwide credit situation will continue or the impact on our future operations and our ability to issue debt at reasonable interest rates. In addition, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. We have substantial amounts of short-term credit facilities that expire in 2009. We intend to seek to renew the facilities on or before the expiration dates. However, we cannot predict the outcome of these efforts, which could result in a decrease in amounts available and/ or an increase in our borrowing costs and negatively impact our financial performance.
 
Poor investment performance of pension and other postretirement benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.  Our costs of providing non-contributory defined benefit pension plans and other postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure


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the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under our plans. We have significant benefit obligations and hold significant assets in trust to satisfy these obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets, as was experienced in 2008, will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in the foreseeable future. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Also, if future increases in pension and postretirement benefit costs as a result of reduced plan assets are not recoverable from Detroit Edison or MichCon customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.
 
If our goodwill becomes impaired, we may be required to record a charge to earnings.  We annually review the carrying value of goodwill associated with acquisitions made by the Company for impairment. Factors that may be considered for purposes of this analysis include any change in circumstances indicating that the carrying value of our goodwill may not be recoverable such as a decline in stock price and market capitalization, future cash flows, and slower growth rates in our industry. We cannot predict the timing, strength or duration of any economic slowdown or subsequent recovery, worldwide or in the economy or markets in which we operate, however, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, the Company may take a non-cash impairment charge, which could potentially materially impact our results of operations and financial position.
 
Our participation in energy trading markets subjects us to risk.  Events in the energy trading industry have increased the level of scrutiny on the energy trading business and the energy industry as a whole. In certain situations we may be required to post collateral to support trading operations, which could be substantial. If access to liquidity to support trading activities is curtailed, we could experience decreased earnings potential and cash flows.
 
We are exposed to credit risk of counterparties with whom we do business.  Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial position, or results of operations.
 
We may not be fully covered by insurance.  We have a comprehensive insurance program in place to provide coverage for various types of risks, catastrophic damage as a result of acts of God, terrorism, war or a combination of other significant unforeseen events that could impact our operations. Economic losses might not be covered in full by insurance or our insurers may be unable to meet contractual obligations.
 
We are subject to rate regulation.  Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers’ rates. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.
 
Michigan’s electric Customer Choice program could negatively impact our financial performance.  The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those


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customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. MPSC rate orders and recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a cap on the total potential Customer Choice related migration. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases.
 
Weather significantly affects operations.  Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Ice storms, tornadoes, or high winds can damage the electric distribution system infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be fully recoverable through the regulatory process.
 
Operation of a nuclear facility subjects us to risk.  Ownership of an operating nuclear generating plant subjects us to significant additional risks. These risks include, among others, plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.
 
The supply and price of fuel and other commodities and related transportation costs may impact our financial results.  We are dependent on coal for much of our electrical generating capacity. Price fluctuations, fuel supply disruptions and increases in transportation costs could have a negative impact on our ability to profitably generate electricity. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. We have hedging strategies and regulatory recovery mechanisms in place to mitigate negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. The price of natural gas also impacts the market for our non-utility businesses that compete with utilities and alternative electric suppliers. Increased transportation costs could also impact our non-utility businesses.
 
Unplanned power plant outages may be costly.  Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.
 
Our estimates of gas reserves are subject to change.  While we cannot provide absolute assurance that our estimates of our Barnett gas reserves are accurate, great care is exercised in utilizing historical information and assumptions to develop reasonable estimates of future production and cash flow. We estimate proved gas reserves and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used.
 
Our ability to utilize production tax credits may be limited.  To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels and electricity from alternative sources. We have generated production tax credits from the synfuel, coke


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production, landfill gas recovery, biomass fired electric generation and gas production operations. We have received favorable private letter rulings on all of the synfuel facilities. All production tax credits taken after 2003 are subject to audit by the Internal Revenue Service (IRS). If our production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in the synfuel facilities.
 
We rely on cash flows from subsidiaries.  DTE Energy is a holding company. Cash flows from our utility and non-utility subsidiaries are required to pay interest expenses and dividends on DTE Energy debt and securities. Should a major subsidiary not be able to pay dividends or transfer cash flows to DTE Energy, our ability to pay interest and dividends would be restricted.
 
Environmental laws and liability may be costly.  We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on potentially responsible parties.
 
We may also incur liabilities as a result of potential future requirements to address climate change issues. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. If increased regulation of greenhouse gas emissions are implemented, the operations of our fossil-fuel generation assets may be significantly impacted.
 
Since there can be no assurances that environmental costs may be recovered through the regulatory process, our financial performance may be negatively impacted as a result of environmental matters.
 
Terrorism could affect our business.  Damage to downstream infrastructure or our own assets by terrorism would impact our operations. We have increased security as a result of past events and further security increases are possible.
 
Benefits of continuous improvement initiatives could be less than we expect.  We have a continuous improvement program that is expected to result in significant cost savings. Actual results achieved through this program could be less than our expectations.
 
A work interruption may adversely affect us.  Unions represent approximately 5,000 of our employees. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.
 
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations.  Our business is dependent on our ability to recruit, retain, and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 3.   Legal Proceedings
 
We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such


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proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.
 
We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could potentially be significant. To date, the Company has not been properly served process in this matter. Nevertheless, as a result of a decision by a Canadian court, a trial schedule has been initiated. The Company believes the claims of the Waterkeeper Alliance in this matter are without legal merit and has appealed the court’s decision. We are not able to predict or assess the outcome of this action at this time.
 
In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. The defendants filed motions to dismiss. The motions are pending before the court. DTE Energy believes this claim is without merit, but is not able to predict or assess the outcome of this lawsuit at this time.
 
The City of Detroit Water and Sewer Department (DWSD) has a suit pending in U.S. District Court for the Eastern District of Michigan against EES Coke Battery, LLC (EES Coke), which is an indirect wholly owned subsidiary of the Company, alleging that certain constituents of waste water discharged by EES Coke into DWSD’s sewer system exceeded the permitted amounts. DWSD has requested that EES Coke be required to obtain a new permit and to pay fines for past excess amounts. DWSD and EES Coke have negotiated a consent order to settle this matter that is expected to require EES Coke to pay fines in excess of $100,000. The consent order is subject to final approval of the court. EES Coke is making capital improvements that are intended to prevent exceedances of the permitted amounts in the future.
 
For additional discussion on legal matters, see Notes 5 and 17 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
We did not submit any matters to a vote of security holders in the fourth quarter of 2008.


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Part II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock. The following table indicates the reported high and low sales prices of our common stock on the Composite Tape of the New York Stock Exchange and dividends paid per share for each quarterly period during the past two years:
 
                                 
                Dividends
                Paid
Year
  Quarter   High   Low   Per Share
 
  2008                              
        First   $ 45.34     $ 37.87     $ 0.530  
        Second   $ 44.82     $ 38.95     $ 0.530  
        Third   $ 44.97     $ 38.78     $ 0.530  
        Fourth   $ 40.92     $ 27.82     $ 0.530  
  2007                              
        First   $ 49.42     $ 45.14     $ 0.530  
        Second   $ 54.74     $ 47.22     $ 0.530  
        Third   $ 51.74     $ 45.26     $ 0.530  
        Fourth   $ 51.19     $ 43.96     $ 0.530  
 
At December 31, 2008, there were 163,019,596 shares of our common stock outstanding. These shares were held by a total of 82,706 shareholders of record.
 
Our Bylaws nullify Chapter 7B of the Michigan Business Corporation Act (Act). This Act regulates shareholder rights when an individual’s stock ownership reaches 20% of a Michigan corporation’s outstanding shares. A shareholder seeking control of the Company cannot require our Board of Directors to call a meeting to vote on issues related to corporate control within 10 days, as stipulated by the Act.
 
We paid cash dividends on our common stock of $344 million in 2008, $364 million in 2007, and $365 million in 2006. The amount of future dividends will depend on our earnings, cash flows, financial condition and other factors that are periodically reviewed by our Board of Directors. Although there can be no assurances, we anticipate paying dividends for the foreseeable future.
 
See Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Report for information on dividend restrictions.
 
All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.
 
See the following table for information as of December 31, 2008.
 
                         
    Number of Securities
      Number of Securities
    to be Issued Upon
  Weighted-Average
  Remaining Available For
    Exercise of
  Exercise Price of
  Future Issuance Under Equity
    Outstanding Options   Outstanding Options   Compensation Plans
 
Plans approved by shareholders
    5,013,699     $ 42.45       4,822,431  


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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act for the year ended December 31, 2008:
 
                                         
            Number
       
            of Shares
      Maximum Dollar
            Purchased as
      Value that May
    Number of
  Average
  Part of Publicly
  Average
  Yet Be
    Shares
  Price
  Announced
  Price Paid
  Purchased Under
    Purchased
  Paid Per
  Plans or
  Per Share
  the Plans or
    (1)   Share (1)   Programs (2)   (2)   Programs (2)
 
01/01/08 — 01/31/08
    34,300     $ 43.96                 $ 822,895,623  
02/01/08 — 02/29/08
    203,670       41.24                   822,895,623  
03/01/08 — 03/31/08
    83,760       38.92                   822,895,623  
04/01/08 — 04/30/08
    22,220       41.46                   822,895,623  
05/01/08 — 05/31/08
    32,000       43.13                   822,895,623  
06/01/08 — 06/30/08
    35,000       43.72                   822,895,623  
07/01/08 — 07/31/08
    1,200       43.07                   822,895,623  
08/01/08 — 08/31/08
    20,000       42.25                   822,895,623  
09/01/08 — 09/30/08
                            822,895,623  
10/01/08 — 10/31/08
    9,455       34.95                   822,895,623  
11/01/08 — 11/30/08
    37,464       36.91                   822,895,623  
12/01/08 — 12/31/08
                            822,895,623  
                                         
Total
    479,069                                  
                                         
 
 
(1) Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program.
 
(2) In January 2005, the DTE Energy Board of Directors authorized the repurchase of up to $700 million of common stock through 2008. In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to an additional $850 million of common stock through 2009. Through December 31, 2008, repurchases of approximately $725 million of common stock were made under these authorizations. These authorizations provide management with flexibility to pursue share repurchases from time to time and will depend on actual and future asset monetizations, cash flows and investment opportunities.


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Item 6.   Selected Financial Data
 
The following selected financial data should be read in conjunction with the accompanying Management’s Discussion and Analysis in Item 7 of this Report and Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
                                         
    2008     2007     2006     2005     2004  
    (In millions, except per share amounts)  
 
Operating Revenues
  $ 9,329     $ 8,475     $ 8,157     $ 8,094     $ 6,419  
                                         
Net Income (Loss)
                                       
Income from continuing operations(1)
  $ 526     $ 787     $ 389     $ 272     $ 265  
Discontinued operations
    20       184       43       268       166  
Cumulative effect of accounting changes
                1       (3 )      
                                         
Net Income
  $ 546     $ 971     $ 433     $ 537     $ 431  
                                         
Diluted Earnings Per Common Share
                                       
Income from continuing operations
  $ 3.23     $ 4.62     $ 2.18     $ 1.55     $ 1.53  
Discontinued operations
    .13       1.08       .24       1.52       .96  
Cumulative effect of accounting changes
                .01       (.02 )      
                                         
Diluted Earnings Per Common Share
  $ 3.36     $ 5.70     $ 2.43     $ 3.05     $ 2.49  
                                         
Financial Information
                                       
Dividends declared per share of common stock
  $ 2.12     $ 2.12     $ 2.075     $ 2.06     $ 2.06  
Total assets
  $ 24,590     $ 23,742     $ 23,785     $ 23,335     $ 21,297  
Long-term debt, including capital leases
  $ 7,741     $ 6,971     $ 7,474     $ 7,080     $ 7,606  
Shareholders’ equity
  $ 5,995     $ 5,853     $ 5,849     $ 5,769     $ 5,548  
 
 
(1) 2007 amounts include $580 million after-tax gain on the Antrim sale transaction and $210 million after-tax losses on hedge contracts associated with the Antrim sale. 2008 amounts include $81 million after-tax gain on the sale of a portion of the Barnett shale properties. See Note 3 of Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
OVERVIEW
 
DTE Energy is a diversified energy company with 2008 operating revenues in excess of $9 billion and over $24 billion in assets. 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.
 
The following table summarizes our financial results:
 
                         
    2008   2007   2006
    (In millions, except earnings per share)
 
Income from continuing operations
  $ 526     $ 787     $ 389  
Diluted earnings per common share from continuing operations
  $ 3.23     $ 4.62     $ 2.18  
Net income
  $ 546     $ 971     $ 433  
Diluted earnings per common share
  $ 3.36     $ 5.70     $ 2.43  
 
The decrease in 2008 from 2007 was primarily due to approximately $370 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $900 million ($580 million after-tax), partially offset by losses recognized on related hedges of $323 million ($210 million


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after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income during 2007. Net income in 2008 was also impacted by a 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:
 
  •  Impacts of national and regional economic conditions on utility operations;
 
  •  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;
 
  •  Fluctuations in market demand on coal supply;
 
  •  Challenges associated with nuclear fuel;
 
  •  Monetization of portions of our Unconventional Gas Production business;
 
  •  Discontinuance of planned monetization of a portion of our Power and Industrial Projects business;
 
  •  Results in our Energy Trading business;
 
  •  Discontinuance of the Synthetic Fuel business; and
 
  •  Required environmental and reliability-related capital investments.
 
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 customers in southeastern Michigan.
 
Our Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 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.
 
Impact of national and regional economic conditions on our utility operations — Revenues from our utility operations follow the economic cycles of the customers we serve. Our utilities provide services to the domestic automotive industry which is under considerable financial distress, exacerbating the decline in regional conditions. In 2008, Detroit Edison experienced a decline in sales in its service territory as compared to 2007. We expect this decline to continue in 2009. As discussed further below, deteriorating economic conditions impact our ability to collect amounts due from our customers of our electric and gas utilities and drive higher levels of lost and stolen natural gas at MichCon. In the face of the economic conditions, we are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength.
 
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 year ended December 31, 2008 we experienced colder weather than the year ended December 31, 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 pre-tax earnings by $61 million in 2008, $68 million in 2007 and $46 million in 2006.
 
Collectibility of Accounts Receivable on Utility Operations — Both utilities continue to experience high levels of past due receivables, which is primarily attributable to economic conditions including high levels of


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unemployment and home foreclosures. High energy prices and a lack of adequate levels of assistance for low-income customers have also impacted our accounts receivable.
 
We have taken actions to manage the level of past due receivables, including 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.
 
Our uncollectible accounts expense for the two utilities increased to $213 million in 2008 from $135 million in 2007 and from $123 million in 2006.
 
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. In December 2008, MichCon received authorization to surcharge $34 million, including a $1 million uncollected balance from the 2005 surcharge, beginning in January 2009. We accrue interest income on the outstanding balances.
 
Impact of Regulatory Decisions on Utility Operations — On December 23, 2008, the MPSC issued an order in Detroit Edison’s February 20, 2008 updated rate case filing. The MPSC approved an annual revenue increase of $84 million effective January 14, 2009 or a 2.0% average increase in Detroit Edison’s annual revenue requirement for 2009. Included in the approved $84 million increase in revenues was a return on equity of 11% on an expected 49% equity and 51% debt capital structure.
 
Other key aspects of the MPSC order include the following:
 
  •  In order to more accurately reflect the actual cost of providing service to business customers, the MPSC adopted an immediate 39% phase out of the residential rate subsidy, with the remaining amount to be eliminated in equal installments over the next five years, every October 1.
 
  •  Accepted Detroit Edison’s proposal to reinstate and modify the tracking mechanism on Electric Choice sales (CIM) with a base level of 1,561 GWh. The modified mechanism will not have a cap on the amount recoverable.
 
  •  Terminated the Pension Equalization Mechanism.
 
  •  Approved an annual reconciliation mechanism to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $110 million and $51 million, respectively.
 
  •  Approved Detroit Edison’s proposal to recover a return on $15 million in working capital associated with the preparation of an application for a new nuclear generation facility at its current Fermi 2 site.
 
The MPSC issued an order on August 31, 2006 approving a settlement agreement providing for an annualized rate reduction of $53 million for 2006 for Detroit Edison, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $76 million in 2007 and approximately $25 million during the period the rate reduction was in effect for 2008, as a result of this order. The revenue reduction was net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provided 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,


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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 $41 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon sold 0.75 Bcf of base gas in 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. 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 — On September 18, 2008, the Michigan House of Representatives and Michigan Senate passed a package of bills to establish a comprehensive, sustainable, long-term energy plan for Michigan. The Governor of Michigan signed the bills on October 6, 2008.
 
The package of bills includes:
 
  •  2008 Public Act (PA) 286 that reforms Michigan’s utility regulatory framework, including the electric Customer Choice program,
 
  •  2008 PA 295 that establishes a renewable portfolio / energy optimization standard and provides a funding mechanism, and
 
  •  2008 PA 287 that provides for an income tax credit for the purchase of energy efficient appliances and a credit to offset a portion of the renewable charge.
 
2008 PA 286 makes the following changes in the regulatory framework for Michigan utilities.
 
  •  Electric Customer Choice reform — The bill establishes a 10 percent limit on participation in the electric Customer Choice program. In general, customers representing 10 percent of a utility’s load may receive electric generation from an electric supplier that is not a utility. After that threshold is met, the remaining customers will remain on full, bundled utility service. As of December 31, 2008, approximately 3 percent of Detroit Edison’s load was on the electric Customer Choice program. The bill also allows continuation of prior MPSC policies for customers to return to full utility service.
 
  •  Cost-of-service based electric rates (deskewing) — The bill requires the MPSC to set rates based on cost-of-service for all customer classes, eliminating over a five-year period the current subsidy by businesses of residential customer rates. This provision does not change total revenue for Detroit Edison. It lowers rates for most commercial and industrial customers and increases rates for residential and certain other industrial customers to match the actual cost of service for each customer class. Rate changes will be phased in over five years, with a 2.5% annual cap on residential rate increases due to deskewing beginning January 1, 2009. Rates for schools and other qualified educational institutions will be set at their cost of service sooner.
 
  •  File and use ratemaking — The bill establishes a 12 month deadline for the MPSC to complete a rate case and allows a utility to self-implement rate changes six months after a rate filing, subject to certain limitations. If the final case order leads to lower rates than the utility had self-implemented, the utility will refund with interest, the difference. In addition, utility rate cases may be based on a forward test year. The bill also has provisions designed to help the MPSC obtain increased funding for additional staff.
 
  •  Certificate of Need process for major capital investments — The bill establishes a certificate of need process for capital projects costing more than $500 million. The process requires the MPSC to review for prudence, prior to construction, proposed investments in new generating assets, acquisitions of existing power plants, major upgrades of power plants, and long-term power purchase agreements. The


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  bill increases the certainty for utilities to recover the cost of projects approved by the MPSC and provides for the utilities to recover interest expenses during construction.
 
  •  Merger & Acquisition approval — The bill grants the MPSC the authority to review and approve proposed utility mergers and acquisitions in Michigan and sets out evaluation criteria.
 
2008 PA 295 establishes renewable energy and energy optimization (energy efficiency, energy conservation or load management) programs in Michigan and provides for a separate funding surcharge to pay the cost of those programs. In accordance with the new law, the MPSC issued a temporary order on December 4, 2008 implementing this act. Within 90 days following the issuance of the temporary order, Detroit Edison is required to file a Renewable Portfolio Standard (RPS) plan with the MPSC. In addition, Detroit Edison and MichCon are required to file Energy Optimization plans with the MPSC.
 
Renewable Energy Standard
 
  •  The bill requires electric providers to source 10% of electricity sold to retail customers from renewable energy resources by 2015.
 
  •  Qualifying renewable energy resources include wind, biomass, solar, hydro, and geothermal, among others.
 
  •  Detroit Edison will be required to have a renewable energy capacity portfolio of 300MW by December 31, 2013 and 600MW by December 31, 2015.
 
  •  The MPSC will establish a per meter surcharge to fund the renewable energy requirements. The recovery mechanism starts prior to actual construction in order to smooth the rate impact for customers.
 
  •  The bill allows for the lowering of compliance if RPS costs exceed the surcharge/cost cap or if other specified factors adversely affect the availability of renewable energy.
 
  •  The bill specifies that a utility can build or have others build and later sell to the utility up to 50 percent of the generation required to meet the RPS. The other 50 percent would be contracted through power purchase agreements.
 
  •  The bill also provides for a net metering program to be established by MPSC order for on-site customer-owned renewable generation up to 1% of an electric utility’s load.
 
Energy Optimization Standard
 
  •  Requires utilities to create electric and natural gas energy optimization plans for each customer class and includes funding surcharges as well as the potential for incentives for exceeding performance goals.
 
  •  For electric sales, the program targets 0.3 percent annual savings in 2009, ramping up to 1 percent annual savings by 2012. Savings percentages are based on prior year retail sales.
 
  •  For natural gas sales, the targeted annual savings start at 0.1 percent in 2009 and ramp up to 0.75 percent by 2012.
 
  •  The MPSC will allow utilities to capitalize certain costs of their energy optimization program. The costs which can be capitalized include equipment, materials, installation costs and customer incentives.
 
  •  Incentives are potentially available for exceeding annual program targets. The financial incentive could be the lesser of 25% of the net cost reduction to our customers or 15% of total program spend, subject to MPSC approval.
 
  •  The bill would also allow a natural gas utility that spends at least 0.5 percent of its revenues on energy efficiency programs to implement a symmetrical decoupling true-up mechanism that adjusts for sales volumes that are above or below the level reflected in its gas distribution rates.
 
  •  By March 2016, the MPSC may suspend the program if it determines the program is no longer cost-effective.


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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 volatility and higher prices which are passed to our customers through the PSCR mechanism. The demand and price volatility have been dampened by the recent economic downturn, but are expected to increase as the economy improves. 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 (Fermi 2) 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 of certain non-utility businesses.
 
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 long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We also hold partnership interests in Millennium Pipeline Company which indirectly connects southern New York State to Upper Midwest/Canadian supply, while providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 87 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facilities are high deliverability storage fields having bi-directional interconnections with Vector Pipeline and MichCon providing our customers access to the Chicago, Michigan, other Midwest and Ontario market centers. The pipeline business is expanding and building new pipeline capacity to serve markets in Northeast United States.
 
Unconventional Gas Production
 
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 62,395 (60,435 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 Portions 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 75 Bcfe of proved 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.


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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 $96 million in the Barnett shale in 2008 and expect to invest approximately $25 million in 2009. During 2009, we expect to drill 15 to 25 new wells and achieve Barnett shale production of approximately 5-6 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.
 
As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of anticipated production from our reserves to secure an attractive investment return. As of December 31, 2008, we have a series of cash flow hedges for approximately 3.2 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.33 per Mcf.
 
Texas — Barnett Shale
 
                         
    2008     2007     2006  
 
Net Producing Wells
                       
Held for sale
          33       27  
Held for use
    155       120       83  
                         
Total
    155       153       110  
Production Volume (Bcfe)
                       
Held for sale
          4.7       2.8  
Held for use
    5.0       3.0       1.3  
                         
Total
    5.0       7.7       4.1  
Proved Reserves (Bcfe)(1)
                       
Held for sale
          75       60  
Held for use
    167       144       111  
                         
Total
    167       219       171  
Net Developed Acreage(1)
                       
Held for sale
          4,987       3,977  
Held for use(2)
    14,248       9,880       10,693  
                         
Total
    14,248       14,867       14,670  
Net Undeveloped Acreage(1)
                       
Held for sale
          5,809       6,164  
Held for use(2)
    46,187       38,066       27,613  
                         
Total
    46,187       43,875       33,777  
Capital Expenditures (in Millions)(3)
                       
Held for sale
  $     $ 45     $ 67  
Held for use
    96       95       61  
                         
Total
  $ 96     $ 140     $ 128  
Future Undiscounted Net Cash Flows (in Millions)(4)
                       
Held for sale
  $     $ 282     $ 167  
Held for use
    324       521       305  
                         
Total
  $ 324     $ 803     $ 472  
Average gas price (per Mcf)
  $ 8.69     $ 6.29     $ 5.66  
 
 
(1) Due to the impairment of acreage and wells in the southern expansion area of the Barnett shale during 2007, the proved reserves and acreage numbers above do not include the southern area. Total net acreage related to impaired leases in the southern expansion area was 23,659 acres and 32,083 acres for the years


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2007 and 2006, respectively. In 2008, an impairment was recorded on approximately 5,600 acres within the western expansion of the Barnett Shale. Impaired acreage and wells are not included in the table above.
 
(2) Developed acreage for continuing operations shows a decrease from 2006 to 2007, which reflects the Company’s experience that spacing of wells in the Barnett shale has been reduced over the years. This reduced spacing estimate drives a shift from developed to undeveloped acreage counts. We continue to expand our total position in the western expansion area of the Barnett shale.
 
(3) Excludes sold and impaired assets in southern expansion area of the Barnett shale.
 
(4) Represents the standardized measure of undiscounted future net cash flows utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.
 
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; provide coal transportation and marketing; and sell electricity from biomass-fired energy projects. This business segment 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 provided include pulverized coal, petroleum coke and metallurgical 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, two biomass-fired electric generating plants and operate one coal-fired power plant. A third biomass-fired electric generating plant is currently under development pending certain regulatory and management approvals with an expected in-service date of January 2010. This business segment 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 the coke batteries generates production tax credits. The business provides coal transportation — related 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 segment 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.
 
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 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, our work on this planned monetization was discontinued. As of June 30, 2008, the assets and liabilities of the Projects are 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 and the optimization of contracted natural gas pipeline transportation 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. 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.


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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 pipeline transportation 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
 
The Synthetic Fuel business was presented as a non-utility segment through the third quarter of 2007. 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 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. To optimize income and cash flow from synfuel operations, we sold interests in all nine of the facilities, representing 91% of the total production capacity. The synthetic fuel plants generated operating losses that were offset by production tax credits.
 
The value of a production tax credit was adjusted annually by an inflation factor and published annually by the IRS. The value of production tax credits for synthetic fuel was reduced when the Reference Price of a barrel of oil exceeded certain thresholds. The actual tax credit phase-out for 2007 was approximately 67%.
 
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. Our electric utility segment currently expects to invest approximately $6 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects during the period of 2009 through 2013. Our gas utility segment currently expects to invest approximately $750 million to $800 million 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. Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.
 
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;
 
  •  managing cash, capital and liquidity to maintain or improve our financial strength;
 
  •  improving Electric and Gas Utility customer satisfaction; and
 
  •  investing in businesses that integrate our assets and leverage our skills and expertise.


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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
 
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 (now the 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 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report for further information on this realignment. The following sections provide a detailed discussion of the operating performance and future outlook of our segments.
 
                         
    2008     2007     2006  
    (In millions)  
 
Net Income by Segment:
                       
Electric Utility
  $ 331     $ 317     $ 325  
Gas Utility
    85       70       50  
Non-utility Operations:
                       
Gas Midstream
    38       34       28  
Unconventional Gas Production(1)
    84       (217 )     9  
Power and Industrial Projects
    40       49       (58 )
Energy Trading
    42       32       96  
Corporate & Other(1)
    (94 )     502       (61 )
Income (Loss) from Continuing Operations:
                       
Utility
    416       387       375  
Non-utility
    204       (102 )     75  
Corporate & Other
    (94 )     502       (61 )
                         
      526       787       389  
Discontinued Operations
    20       184       43  
Cumulative Effect of Accounting Changes
                1  
                         
Net Income
  $ 546     $ 971     $ 433  
                         
 
 
(1) 2008 net income of the Unconventional Gas Production segment resulted principally from the gain on the sale of a portion of our Barnett shale properties. 2007 net loss resulted principally from the recognition of losses on hedge contracts associated with the Antrim sale transaction. 2007 net income of the Corporate & Other segment resulted principally from the gain recognized on the Antrim sale transaction. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
ELECTRIC UTILITY
 
Our Electric Utility segment consists of Detroit Edison.
 
Factors impacting income:  Net income increased $14 million in 2008 and decreased $8 million in 2007. The 2008 increase was primarily due to lower expenses for operation and maintenance, depreciation and amortization, and taxes other than income, partly offset by lower gross margins and higher income tax expense. The 2007 decrease reflects higher operation and maintenance expenses, partially offset by higher gross margins and lower depreciation and amortization expenses.
 


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    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 4,874     $ 4,900     $ 4,737  
Fuel and Purchased Power
    1,778       1,686       1,566  
                         
Gross Margin
    3,096       3,214       3,171  
Operation and Maintenance
    1,322       1,422       1,336  
Depreciation and Amortization
    743       764       809  
Taxes Other Than Income
    232       277       252  
Asset (Gains) Losses and Reserves, Net
    (1 )     8       (6 )
                         
Operating Income
    800       743       780  
Other (Income) and Deductions
    283       277       294  
Income Tax Provision
    186       149       161  
                         
Net Income
  $ 331     $ 317     $ 325  
                         
Operating Income as a Percent of Operating Revenues
    16 %     15 %     16 %
 
Gross margin decreased $118 million during 2008 and increased $43 million in 2007. The 2008 decrease was due to the unfavorable impacts of weather and service territory performance and the absence of the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation. These 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. The increase in 2007 was attributed to higher margins due to returning sales from electric Customer Choice, the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and weather related impacts, partially offset by lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding and the unfavorable impact of a September 2006 MPSC order related to the 2004 PSCR reconciliation. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.
 
The following table displays changes in various gross margin components relative to the comparable prior period:
 
                 
Increase (Decrease) in Gross Margin Components Compared to Prior Year
  2008     2007  
    (In millions)  
 
Weather-related impacts
  $ (37 )   $ 31  
Return of customers from electric Customer Choice
    35       43  
Service territory performance
    (100 )     28  
Refundable pension cost
    (30 )      
April 2008 expiration of show cause rate decrease
    46        
Impact of 2006 MPSC show cause order
          (64 )
Impact of 2005 MPSC PSCR reconciliation order
    (38 )     38  
Impact of 2004 MPSC PSCR reconciliation order
          (39 )
Other, net
    6       6  
                 
Increase (decrease) in gross margin
  $ (118 )   $ 43  
                 
 

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Power Generated and Purchased
  2008     2007     2006  
    (In thousands of MWh)  
 
Power Plant Generation
                                               
Fossil
    41,254       71 %     42,359       72 %     39,686       70 %
Nuclear
    9,613       17       8,314       14       7,477       13  
                                                 
      50,867       88       50,673       86       47,163       83  
Purchased Power
    6,877       12       8,422       14       9,861       17  
                                                 
System Output
    57,744       100 %     59,095       100 %     57,024       100 %
Less Line Loss and Internal Use
    (3,445 )             (3,391 )             (3,603 )        
                                                 
Net System Output
    54,299               55,704               53,421          
                                                 
Average Unit Cost ($/MWh)
                                               
Generation(1)
  $ 17.93             $ 15.83             $ 15.61          
                                                 
Purchased Power
  $ 69.50             $ 62.40             $ 53.71          
                                                 
Overall Average Unit Cost
  $ 24.07             $ 22.47             $ 22.20          
                                                 
 
 
(1) Represents fuel costs associated with power plants.
 
                         
    2008     2007     2006  
    (In thousands of MWh)  
 
Electric Sales
                       
Residential
    15,492       16,147       15,769  
Commercial
    18,920       19,332       17,948  
Industrial
    13,086       13,338       13,235  
Wholesale
    2,825       2,902       2,826  
Other
    393       398       402  
                         
      50,716       52,117       50,180  
Interconnection sales(1)
    3,583       3,587       3,241  
                         
Total Electric Sales
    54,299       55,704       53,421  
                         
Electric Deliveries
                       
Retail and Wholesale
    50,716       52,117       50,180  
Electric Customer Choice
    1,382       1,690       2,694  
Electric Customer Choice — Self Generators(2)
    75       549       909  
                         
Total Electric Sales and Deliveries
    52,173       54,356       53,783  
                         
 
 
(1) Represents power that is not distributed by Detroit Edison.
 
(2) Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.
 
Operation and maintenance expense decreased $100 million in 2008 and increased $86 million in 2007. The decrease in 2008 was due primarily to lower information systems implementation costs of $60 million, lower benefit expense of $45 million and lower corporate support expenses of $29 million, partially offset by higher uncollectible expenses of $22 million. The increase in 2007 is primarily due to higher information systems implementation costs of $30 million, higher storm expenses of $22 million, increased uncollectible expense of $22 million and higher corporate support expenses of $20 million.

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Depreciation and amortization expense decreased $21 million in 2008 and $45 million in 2007. The 2008 decrease was due primarily to decreased amortization of regulatory assets. The 2007 decrease was due primarily to a 2006 net stranded cost write-off of $112 million related to the September 2006 MPSC order regarding stranded costs and a $13 million decrease in our asset retirement obligation at our Fermi 1 nuclear facility, partially offset by $58 million of increased amortization of regulatory assets and $13 million of higher depreciation expense due to increased levels of depreciable plant assets.
 
Taxes other than income decreased $45 million in 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.
 
Asset (gains) losses and reserves, net decreased $9 million in 2008 and increased $14 million in 2007 due to a 2007 $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal).
 
Other (income) and deductions expense increased $6 million in 2008 and decreased $17 million in 2007. The 2008 increase is attributable to $15 million of investment losses in a trust utilized for retirement benefits and $3 million of miscellaneous expenses offset by higher capitalized interest of $12 million. The 2007 decrease is attributable to a $10 million contribution to the DTE Energy Foundation in 2006 that did not recur in 2007, $3 million of higher interest income and $17 million of increased miscellaneous utility related services, partially offset by $16 million of higher interest expense.
 
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 by pursuing regulatory and/or legislative solutions. Many of these issues and problems have been addressed by the legislation signed by the Governor of Michigan in October 2008, discussed more fully in the Overview section. Looking forward, additional issues, such as volatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans, health care costs 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.
 
Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.
 
Due to the economy and credit market conditions, in the near term, we are reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust the timing of projects as appropriate. Long term, we will be required to invest an estimated $2.8 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 economic and 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.
 
On September 18, 2008, Detroit Edison submitted a Combined Operating License Application with the NRC for construction and operation of a possible 1,500 MW nuclear power plant at the site of the company’s existing Fermi 2 nuclear plant. We have not decided on construction of a new base-load nuclear plant; however, by completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005. In addition, Detroit Edison is also moving ahead with plans for renewable energy resources and an aggressive energy efficiency program.
 
The following variables, either individually or in combination, could impact our future results:
 
  •  Access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;


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  •  Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on cash equivalents and investments;
 
  •  Economic conditions within Michigan and corresponding impacts on demand for electricity;
 
  •  Collectibility of accounts receivable;
 
  •  Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions;
 
  •  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;
 
  •  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:  Gas Utility’s net income increased $15 million in 2008 and $20 million in 2007. The 2008 and 2007 increases were due primarily to higher gross margins.
 
                         
    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 2,152     $ 1,875     $ 1,849  
Cost of Gas
    1,378       1,164       1,157  
                         
Gross Margin
    774       711       692  
Operation and Maintenance
    464       429       431  
Depreciation and Amortization
    102       93       94  
Taxes Other Than Income
    48       56       53  
Asset (Gains) and Losses, Net
    (26 )     (3 )      
                         
Operating Income
    186       136       114  
Other (Income) and Deductions
    60       43       53  
Income Tax Provision (Benefit)
    41       23       11  
                         
Net Income
  $ 85     $ 70     $ 50  
                         
Operating Income as a Percent of Operating Revenues
    9 %     7 %     6 %
 
Gross margin increased $63 million and $19 million in 2008 and 2007, respectively. The increase in 2008 reflects $49 million from the uncollectible tracking mechanism, $15 million related to the impacts of colder weather, $10 million favorable result of lower lost gas recognized and higher valued gas received as compensation for transportation of third party customer gas, $7 million of 2007 GCR disallowances, and $6 million of appliance repair revenue. The 2008 improvement was partially offset by $19 million of lower storage services revenue and $12 million from customer conservation and lower volumes. The increase in 2007 is primarily due to $21 million from the favorable effects of weather in 2007 and $28 million related to an increase in midstream services including storage and transportation, partially offset by a $26 million unfavorable impact in lost gas recognized and $7 million in GCR disallowances. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.
 


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    2008     2007     2006  
 
Gas Markets (in Millions)
                       
Gas sales
  $ 1,824     $ 1,536     $ 1,541  
End user transportation
    143       140       135  
                         
      1,967       1,676       1,676  
Intermediate transportation
    73       70       69  
Storage and other
    112       129       104  
                         
    $ 2,152     $ 1,875     $ 1,849  
                         
Gas Markets (in Bcf)
                       
Gas sales
    148       148       138  
End user transportation
    123       132       136  
                         
      271       280       274  
Intermediate transportation
    438       399       373  
                         
      709       679       647  
                         
 
Operation and maintenance expense increased $35 million in 2008 and decreased $2 million in 2007. The 2008 increase is primarily attributable to $56 million of higher uncollectible expenses, partially offset by $14 million of lower corporate support expenses and $14 million of reduced pension and retiree health benefit costs. The increase in uncollectible expense is partially offset by increased revenues from the uncollectible tracking mechanism included in the gross margin discussion. The 2007 decrease was attributed to $4 million of lower uncollectible expense and $4 million of reduced corporate support expenses, partially offset by $5 million in increased information systems implementation costs.
 
Other Asset (gains) losses, net increased $23 million in 2008 and $3 million in 2007. Both increases are primarily attributable to the sale of base gas.
 
Outlook — Higher gas prices and deteriorating economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s GCR and uncollectible true-up mechanisms. We will continue to seek opportunities to improve productivity, minimize lost gas, remove waste and decrease our costs while improving customer satisfaction.
 
Unfavorable national and regional economic trends have resulted in negative customer growth in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.
 
The following variables, either individually or in combination, could impact our future results:
 
  •  Access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;
 
  •  Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on cash equivalents and investments;
 
  •  Economic conditions within Michigan and corresponding impacts on demand for gas and levels of lost or stolen gas;
 
  •  Collectibility of accounts receivable;
 
  •  Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions;
 
  •  The amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;

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  •  Our ability to reduce costs and maximize distribution system performance;
 
  •  Variations in market prices of gas;
 
  •  Weather;
 
  •  Customer conservation;
 
  •  Volatility in the short-term storage markets which impact third-party storage revenues;
 
  •  Extent and timing of any base gas sales;
 
  •  Any potential new federal and state environmental, renewable energy and energy efficiency requirements.
 
NON-UTILITY OPERATIONS
 
Gas Midstream
 
Our Gas Midstream segment consists of our non-utility gas pipelines and storage businesses.
 
Factors impacting income:  Net income increased $4 million and $6 million in 2008 and 2007, respectively. The 2008 increase is due to higher storage revenues related to expansion of capacity and higher other income primarily driven by higher equity earnings from our investments in the Vector and Millennium Pipelines, partially offset by a higher tax provision due to the MBT in 2008. Net income was higher in 2007 due to higher storage revenues and lower expenses due to the Washington 10 restructuring during 2006.
 
                         
    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 71     $ 66     $ 63  
Operation and Maintenance
    12       13       22  
Depreciation and Amortization
    5       6       3  
Taxes Other Than Income
    3       3       4  
Asset (Gains) and Losses, Net
    1       (1 )     (1 )
                         
Operating Income
    50       45       35  
Other (Income) and Deductions
    (12 )     (7 )     (8 )
Income Tax Provision
    24       18       15  
                         
Net Income
  $ 38     $ 34     $ 28  
                         
 
Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, an additional 7 Bcf of storage capacity was placed in service. Future additions to storage capacity of approximately 3 Bcf will occur over the next few months. 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, which will expand the Vector Pipeline by approximately 100 MMcf/d, with a proposed in-service date of November 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. Millennium Pipeline was placed in service in December 2008 and 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 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 $1.262 billion.


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In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 75 Bcf of proved 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 2008 results include the gain recognized on the sale of our Barnett shale property described above. 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. The 2007 results reflect the recording of $323 million of losses on financial contracts related to expected Antrim gas production and sales through 2013.
 
                         
    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 48     $ (228 )   $ 99  
Operation and Maintenance
    22       36       37  
Depreciation, Depletion and Amortization
    12       22       27  
Taxes Other Than Income
    1       8       11  
Asset (Gains) and Losses, Net
    (120 )     27       (3 )
                         
Operating Income (Loss)
    133       (321 )     27  
Other (Income) and Deductions
    2       13       13  
Income Tax Provision (Benefit)
    47       (117 )     5  
                         
Net Income (Loss)
  $ 84     $ (217 )   $ 9  
                         
 
Operating revenues increased $276 million in 2008 and decreased $327 million in 2007. The 2007 decrease reflects the recording of $323 million of losses during 2007 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. In conjunction with the Antrim sale, Antrim reclassified amounts held in accumulated other comprehensive income, reducing operating revenues in the 2007 period by $323 million. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $47 million in 2008 as compared to 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.
 
Other assets (gains) losses, net increased $147 million in 2008 due to the gain on sale of Barnett shale core properties offset by $8 million of impairment losses primarily related to leases on unproved acreage that expire in 2009 that we do not anticipate developing due to current economic conditions. The $30 million decrease in 2007 was primarily due to the recording of impairment losses of $27 million in 2007 related to the write-off of unproved properties and the expiration of leases in the southern expansion area of the Barnett shale.
 
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 $96 million in the Barnett shale in 2008. During 2009, we expect to invest approximately $25 million to drill 15 to 25 new wells and achieve Barnett shale production of approximately 5 to 6 Bcfe of natural gas from our remaining properties, compared with approximately 5 Bcfe in 2008.
 
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; provide coal transportation services and marketing; and sell electricity from biomass-fired energy projects.


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During the third quarter of 2007, we announced 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 weakened and challenges in the debt market persisted. As a result of these developments, our work on this planned monetization was 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:  Net income decreased $9 million in 2008 and increased $107 million in 2007.
 
                         
    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 987     $ 1,244     $ 1,053  
Operation and Maintenance
    899       1,143       972  
Depreciation and Amortization
    34       41       49  
Taxes other than Income
    12       13       13  
Other Asset (Gains) and Losses, Reserves and Impairments, Net
    6             76  
                         
Operating Income (Loss)
    36       47       (57 )
Other (Income) and Deductions
    (20 )     (11 )     43  
Minority Interest
    5       2       1  
Income Taxes
                       
Provision (Benefit)
    18       18       (31 )
Production Tax Credits
    (7 )     (11 )     (12 )
                         
      11       7       (43 )
                         
Net Income (Loss)
  $ 40     $ 49     $ (58 )
                         
 
Operating revenues decreased $257 million in 2008.  This was primarily attributable to $177 million of reductions in coal transportation and trading volumes and $28 million for the impact of a customer electing to purchase coal directly from the supplier. Revenues in 2007 increased $191 million reflecting a new long-term utility services contract with a large automotive company, higher coke prices and sales volumes in addition to higher volumes at several other projects. Additionally, revenue was earned for a one-time fee from the sale of an asset we operated for a third party. In 2007, revenues were impacted by higher synfuel related volumes and increases in trading volumes related to both coal and emissions.
 
Operation and maintenance expense decreased $244 million in 2008 and increased $171 million in 2007. The 2008 decrease mostly reflects $174 million of lower coal transportation costs driven by reduced sales combined with a reduction in coal trading results. The 2007 increase was due to higher synfuel related production and higher trading volumes related to coal and emissions.
 
Depreciation and amortization expense decreased $7 million in 2008 and $8 million in 2007 due primarily to the suspension of $6 million of depreciation expense in the fourth quarter of 2007 related to the assets held for sale, the sale of a generation facility during the year and reduced depreciation expense as a result of asset impairments at several biomass landfill sites in 2006.
 
Other assets (gains) losses, reserves and impairments, net expense decreased $6 million in 2008 and decreased $76 million in 2007. The 2008 decrease is 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 the 2008 loss were gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production. The 2007 decrease is due to impairments recognized in 2006 at natural gas- fired generating plants, long-lived assets at several landfill gas recovery sites and fixed assets and patents at our waste coal recovery business


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Other (income) and deductions were higher by $9 million in 2008 due primarily to higher inter-company interest. The 2007 decrease was due primarily to a realized gain of $8 million on the sale of a 50 percent equity interest in a natural gas-fired generating plant and a $4 million gain recognized in 2007 on an installment sale of a coke battery facility.
 
Outlook — The deterioration in the U.S. economy is expected to continue to negatively impact our customers in the steel industry and we expect a corresponding reduction in demand for metallurgical coke and pulverized coal supplied to these customers in 2009. We supply onsite energy services to the domestic automotive manufacturers who have also been negatively affected by the economic downturn and constriction in the capital and credit markets. Our onsite energy services are delivered in accordance with the terms of long-term contracts which include termination payments in the event of plant closures or other events of default and have not been significantly impacted by the financial distress experienced by the automotive manufacturers. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on the results of our onsite energy projects. We continue to monitor developments in this sector. In 2009, we expect our coal transportation and marketing business to positively contribute to the results of this segment as our coal transportation, storage and blending services continue to grow. In 2011, our existing long-term rail transportation contract which gives us a competitive advantage will expire. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers.
 
Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional on-site energy projects to serve energy intensive industrial customers that are experiencing capital constraints due to the economic downturn. We will also continue to look for opportunities to acquire on-site energy projects and biomass fired generating projects for advantageous prices.
 
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 pipeline transportation and storage, and power transmission and generating capacity positions.
 
Factors impacting income:  Net income increased $10 million in 2008 and decreased $64 million in 2007.
 
                         
    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 1,388     $ 924     $ 828  
Fuel, Purchased Power and Gas
    1,235       806       607  
                         
Gross Margin
    153       118       221  
Operation and Maintenance
    68       58       65  
Depreciation and Amortization
    5       5       6  
Taxes Other Than Income
    2       1       1  
                         
Operating Income (Loss)
    78       54       149  
Other (Income) and Deductions
    5       5       4  
Income Tax Provision (Benefit)
    31       17       49  
                         
Net Income (Loss)
  $ 42     $ 32     $ 96  
                         
 
Gross margin increased $35 million in 2008 and decreased $103 million in 2007. The 2008 increase is due to higher unrealized margin of $66 million offset by a decrease in realized margin of $31 million. The increase in unrealized margins includes $18 million in improved gains in the gas trading strategy, $26 million gains on economic hedges of storage positions due to falling gas prices, and the absence of $30 million in mark-to-market losses in June 2007 reflecting revisions of valuation estimates for natural gas contracts, offset by $10 million in losses on economic hedges in our gas transportation strategy. The decrease in realized


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margin is due to unfavorability of $28 million primarily from our power marketing and transmission optimization strategies, $34 million of unfavorability in our gas storage and full requirements strategies due to falling prices in 2008, offset by $31 million of improvement in our gas trading strategy. The 2007 decrease is attributable to approximately $30 million of unrealized losses for gas contracts related to revisions of valuation estimates for the long-dated portion of our energy contracts and $32 million due to absence of unrealized gains on economic storage hedges and positions in our full requirements strategy. Timing differences from 2005 that largely reversed and favorably impacted 2006 margin resulted in $11 million of realized unfavorability in 2007. Additionally, margins were unfavorably impacted by $13 million of lower realized gains from reduced merchant storage capacity in 2007 and $12 million of unfavorability in realized power positions.
 
Operation and maintenance expense increased $10 million in 2008 and decreased $7 million in 2007. The 2008 increase is due to higher payroll and incentive costs and allocated corporate costs. The 2007 decrease was due primarily to lower incentive expenses.
 
Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipeline transportation and certain 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 contracts and assets. A source 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. Our strategy is to economically manage the price risk of storage with futures, forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.
 
See Capital Resources and Liquidity and Fair Value sections that follow for additional discussion of our trading activities.
 
CORPORATE & OTHER
 
Corporate & Other includes various holding company activities and holds certain non-utility debt and energy-related investments.
 
Factors impacting income:  Corporate & Other results decreased by $597 million in 2008 and increased by $563 million in 2007. This is mostly attributable to the 2007 gain on the sale of the Antrim shale gas exploration and production business for approximately $900 million ($580 million after-tax) and variations in inter-company interest.
 
DISCONTINUED OPERATIONS
 
Synthetic Fuel
 
The Company discontinued the operations of our synthetic fuel production facilities 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 offset by production tax credits.
 
Factors impacting income:  Synthetic Fuel net income decreased $185 million in 2008 and increased $157 million in 2007. The decrease in 2008 was due to the cessation of operations of our synfuel facilities at December 31, 2007 and the final determination of the 2007 IRS reference price and inflation factor in 2008. The increase in 2007 was due to synfuel production occurring throughout the year in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006 and higher income from oil price hedges, partially offset by a higher phase-out of production tax credits due to high oil prices.
 


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    2008     2007     2006  
    (In millions)  
 
Operating Revenues
  $ 7     $ 1,069     $ 863  
Operation and Maintenance
    9       1,265       1,019  
Depreciation and Amortization
    (2 )     (6 )     24  
Taxes other than Income
    (1 )     5       12  
Asset (Gains) and Losses, Reserves and Impairments, Net(1)
    (31 )     (280 )     40  
                         
Operating Income (Loss)
    32       85       (232 )
Other (Income) and Deductions
    (2 )     (9 )     (20 )
Minority Interest
    2       (188 )     (251 )
Income Taxes
                       
Provision (Benefit)
    13       98       14  
Production Tax Credits
    (1 )     (21 )     (23 )
                         
      12       77       (9 )
                         
Net Income(1)
  $ 20     $ 205     $ 48  
                         
 
 
(1) Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.
 
Operating revenues decreased $1,062 million in 2008 and increased $206 million in 2007. The 2008 drop is 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. Synfuel production was higher in 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.
 
Operation and maintenance expense decreased $1,256 million in 2008 and increased $246 million in 2007. The 2008 reduction is due to the cessation of operations of our synfuel facilities at December 31, 2007. Activity for 2008 reflects adjustments to 2007 contractually defined cost sharing mechanisms with suppliers, as determined by applying the actual phase-out percentage. The 2007 increase reflects synfuel production occurring throughout 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.
 
Depreciation and amortization expense was lower by $30 million in 2007 as a result of reductions in asset retirement obligations in 2007 and the impairment of fixed assets at all nine synfuel projects in 2006.
 
Asset (gains) and losses, reserves and impairments, net decreased $249 million in 2008 and increased $320 million in 2007. The 2008 decrease was due to the cessation of operations of our synfuel facilities at December 31, 2007 and reflects the impact of reserve adjustments for the final phase-out percentage and true-ups of final payments and distributions to partners.
 
The increase in gains in 2007 reflects the annual partner payment adjustment, recognition of certain fixed gains that were reserved during the comparable 2006 period, higher hedge gains and the impact of one-time impairment charges and fixed note reserves recorded in 2006. In 2007 and 2006, we deferred gains from the sale of the synfuel facilities, including a portion of gains related to fixed payments. Due to the increase in oil prices, we recorded accruals for contractual partners’ obligations of $130 million in 2007 and $79 million in 2006 reflecting the probable refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be paid by our partners. In 2007, we reversed $3 million of other synfuel-related reserves and impairments and in 2006 recorded $78 million of other synfuel-related reserves and impairments. To economically hedge our exposure to the risk of an increase in oil prices and the resulting reduction in synfuel sales proceeds, we entered into derivative and other contracts. The derivative contracts are marked-to-market with changes in their fair value recorded as an adjustment to synfuel gains. We recorded net 2007 synfuel hedge mark-to-market gains of $196 million compared with net 2006 synfuel hedge mark-to-market gains of $60 million.

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The following table displays the various pre-tax components that comprise the determination of synfuel gains and losses in 2008, 2007 and 2006.
 
                         
Components of Asset (Gains) Losses, Reserves and
                 
Impairments, Net
  2008     2007     2006  
    (In millions)  
 
Gains recognized associated with fixed payments
  $     $ (172 )   $ (43 )
Gains recognized associated with variable payments
    (32 )     (39 )     (14 )
Reserves recorded for contractual partners’ obligations
          130       79  
Other reserves and impairments, including partners’ share(1)
    (1 )     (3 )     78  
Hedge (gains) losses:
                       
Hedges for 2006 exposure
                (66 )
Hedges for 2007 exposure
            (196 )     6  
                         
    $ (33 )   $ (280 )   $ 40  
                         
 
 
(1) Includes $70 million in 2006, representing our partners’ share of the asset impairment, included in Minority Interest.
 
Minority interest decreased by $190 million and $63 million in 2008 and 2007, respectively. The 2008 reduction is due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2007 decrease reflects the lower net operating losses in 2007 due to the asset impairment charge we incurred in 2006, partially offset by an increased discount on higher sales levels for 2007.
 
See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
 
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.
 
Effective January 1, 2007, we adopted FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $5 million reduction to the January 1, 2007 balance of retained earnings.
 
Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares.
 
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 2008, our cash requirements were met primarily through operations and from our non-utility monetization program.
 
Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2009 of up to $1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We incurred environmental expenditures of approximately $270 million in 2008 and we expect over $2.9 billion of future capital expenditures through 2018 to satisfy both existing and proposed new requirements. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.


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We expect non-utility capital spending will approximate $175 million to $300 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.
 
Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.
 
Long-term debt maturing or remarketing in 2009 totals approximately $350 million.
 
                         
    2008     2007     2006  
    (In millions)  
 
Cash and Cash Equivalents
                       
Cash Flow From (Used For)
                       
Operating activities:
                       
Net income
  $ 546     $ 971     $ 433  
Depreciation, depletion and amortization
    899       926       1,014  
Deferred income taxes
    348       144       28  
Gain on sale of non-utility business
    (128 )     (900 )      
Gain on sale of synfuel and other assets, net and synfuel impairment
    (35 )     (253 )     28  
Working capital and other
    (71 )     237       (47 )
                         
      1,559       1,125       1,456  
                         
Investing activities:
                       
Plant and equipment expenditures — utility
    (1,183 )     (1,035 )     (1,126 )
Plant and equipment expenditures — non-utility
    (190 )     (264 )     (277 )
Acquisitions, net of cash acquired
                (42 )
Proceeds from sale of non-utility business
    253       1,262        
Proceeds (refunds) from sale of synfuels and other assets
    (278 )     417       313  
Restricted cash and other investments
    (125 )     (50 )     (62 )
                         
      (1,523 )     330       (1,194 )
                         
Financing activities:
                       
Issuance of long-term debt and common stock
    1,310       50       629  
Redemption of long-term debt
    (446 )     (393 )     (687 )
Repurchase of long-term debt
    (238 )            
Short-term borrowings, net
    (340 )     (47 )     291  
Repurchase of common stock
    (16 )     (708 )     (61 )
Dividends on common stock and other
    (354 )     (370 )     (375 )
                         
      (84 )     (1,468 )     (203 )
                         
Net Increase (Decrease) in Cash and Cash Equivalents
  $ (48 )   $ (13 )   $ 59  
                         
 
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.
 
Cash from operations totaling $1.6 billion in 2008, increased $434 million from the comparable 2007 period. The operating cash flow comparison 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 payments received related to our synfuel program hedges.


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Cash from operations totaling $1.1 billion in 2007 decreased $331 million from the comparable 2006 period. The operating cash flow comparison primarily reflects a decrease in net income after adjusting for non-cash items (depreciation, depletion and amortization and deferred taxes) and gains on sales of businesses. The decrease was mostly driven by taxes attributable to our non-utility monetization program.
 
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. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.
 
Net cash used for investing activities was approximately $1.5 billion in 2008, compared with cash from investing activities of $330 million in 2007. The change was primarily driven by our non-utility monetization program and final refund payments to our synfuel partners in 2008.
 
Net cash from investing activities increased $1.5 billion in 2007, due primarily to the sale of our Antrim shale gas exploration and production business and lower capital expenditures.
 
Cash from Financing Activities
 
We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by our operations.
 
Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% to 52%, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet.
 
Net cash used for financing activities was $84 million in 2008, compared to net cash used of approximately $1.5 billion for the same period in 2007. The change was primarily attributable to increased proceeds from the issuance of long-term debt, net of debt redemptions and repurchases, and lower repurchases of common stock.
 
Net cash used for financing activities increased $1.3 billion in 2007 primarily related to the repurchase of common stock, a decrease in short-term borrowings and a lower level of long-term debt issuances, partially offset by lower debt redemptions.
 
Outlook
 
We expect cash flow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We may 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 and maintaining flexibility in the timing and extent of our long-term capital projects.


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Recent distress in the financial markets has had an adverse impact on financial market activities, including extreme volatility in security prices and severely diminished liquidity and credit availability. Pursuant to the failures of large financial institutions, the credit situation rapidly evolved into a global crisis resulting in a number of international bank failures and declines in various stock indexes, and large reductions in the market value of equities and commodities worldwide. The crisis has led to increased volatility in the markets for both financial and physical assets, as the failures of large financial institutions resulted in sharply reduced trading volumes and activity. The effects of the credit situation will continue to be monitored.
 
We have experienced difficulties in accessing the commercial paper markets for short-term financing needs and an extended period of distress in the capital markets could have a negative impact on our liquidity in the future. Short-term borrowings, principally in the form of commercial paper, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities. Beginning late in the third quarter of 2008, access to the commercial paper markets was sharply reduced and, as a result, we drew against our unsecured credit lines to supplement other sources of funds to meet our short-term liquidity needs. We continue to access the long-term bond markets as evidenced by certain financings completed in the fourth quarter of 2008. Since December 31, 2008, we have benefited from substantially improved liquidity and pricing in the commercial paper market. As a result, we anticipate repayment of our credit facility draws during the first quarter of 2009.
 
Approximately $1.2 billion of our total short-term credit arrangements of $2.1 billion expire between June and December 2009, with the remainder expiring in October 2010. In anticipation of a significantly more challenging credit market, we expect to pursue the renewal of $975 million of our syndicated revolving credit facilities before their expiration in October. Given current conditions in the credit markets, we anticipate that the new facilities will vary significantly from our current facilities with respect to such items as bank participation, allocation levels, pricing and covenants. We are currently in discussions with our existing bank group and actively pursuing potential new candidates for inclusion, as we anticipate that a number of banks in our current bank group will elect not to participate in the renewal or will alter their commitment level. Initial indications are that pricing is likely to be significantly higher due to market-wide re-pricing of risk. Multi-year agreements are still possible, however, the recent trend in the marketplace is toward 364 day facilities. Several bi-lateral credit facilities totaling approximately $200 million will also expire in 2009 and we are evaluating the need for replacement.
 
Our benefit plans have not experienced any direct significant impact on liquidity or counterparty risk due to the turmoil in the financial markets. As a result of losses experienced in the financial markets, our benefit plan assets experienced negative returns for 2008, which will result in increased benefit costs and higher contributions in 2009 and future years than in the recent past or than originally planned.
 
We have assessed the implications of these factors on our current business and determined that there has not been a significant impact to our financial position and results of operations in 2008. While the impact of continued market volatility and turmoil in the credit markets cannot be predicted, we believe we have sufficient operating flexibility, cash resources and funding sources to maintain adequate amounts of liquidity and to meet our future operating cash and capital expenditure needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact earnings and cash flows.
 
See Notes 11 and 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


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Contractual Obligations
 
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2008:
 
                                         
                            2014
 
Contractual Obligations
  Total     2009     2010-2011     2012-2013     and Beyond  
    (In millions)  
 
Long-term debt:
                                       
Mortgage bonds, notes and other
  $ 6,687     $ 220     $ 1,294     $ 671     $ 4,502  
Securitization bonds
    1,064       132       290       341       301  
Trust preferred-linked securities
    289                         289  
Capital lease obligations
    91       15       26       18       32  
Interest
    6,104       484       884       722       4,014  
Operating leases
    238       36       57       46       99  
Electric, gas, fuel, transportation and storage purchase obligations(1)
    5,665       2,972       1,813       160       720  
Other long-term obligations(2)(3)(4)
    201       41       94       25       41  
                                         
Total obligations
  $ 20,339     $ 3,900     $ 4,458     $ 1,983     $ 9,998  
                                         
 
 
(1) Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.
 
(2) Includes liabilities for unrecognized tax benefits of $72 million.
 
(3) Excludes other long-term liabilities of $182 million not directly derived from contracts or other agreements.
 
(4) At December 31, 2008, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Critical Accounting Estimates section of MD&A and in Note 18 of the Notes to Consolidated Financial Statements.
 
Credit Ratings
 
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.
 
As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the credit rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the credit rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if the parent is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. While we currently do not anticipate such a


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downgrade, we cannot predict the outcome of current or future credit rating agency reviews. The following table shows our credit rating as determined by three nationally recognized credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.
 
                 
        Credit Rating Agency
        Standard &
  Moody’s
  Fitch
Entity
  Description   Poor’s   Investors Service   Ratings
 
DTE Energy
  Senior Unsecured Debt   BBB-   Baa2   BBB
    Commercial Paper   A-2   P-2   F2
Detroit Edison
  Senior Secured Debt   A-   A3   A-
    Commercial Paper   A-2   P-2   F2
MichCon
  Senior Secured Debt   BBB+   A3   BBB+
    Commercial Paper   A-2   P-2   F2
 
CRITICAL ACCOUNTING ESTIMATES
 
The preparation of financial statements in conformity with generally accepted accounting principles require that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of these accounting policies can be found in the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Regulation
 
A significant portion of our business is subject to regulation. Detroit Edison and MichCon currently meet the criteria of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of SFAS No. 71 for some or all of our businesses. Management believes that currently available facts support the continued application of SFAS No. 71 and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment. See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Derivatives and Hedging Activities
 
Risk management and trading activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives are recorded at fair value and shown as Derivative Assets or Liabilities in the Consolidated Statements of Financial Position. Derivatives are measured at fair value, and changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchases and normal sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. Essentially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.
 
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of derivative contracts is


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determined from a combination of active quotes, published indexes and mathematical valuation models. We generally derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods in which external market data is not readily observable, we estimate value using mathematical valuation models. Valuation models require various inputs and assumptions, including forward prices, volatility, interest rates, and exercise periods. For those inputs which are not observable, we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes, current market transactions or other observable market information may require us to record gains or losses at inception of new derivative contracts.
 
The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. Actual cash returns realized on our derivatives may be different from the results we estimate using models. As fair value calculations are estimates based largely on commodity prices, we perform sensitivity analysis on the fair values of our forward contracts. See sensitivity analysis in the Fair Value section. See Notes 15 and 16 of the Notes to Consolidated Financial Statements in Item 8 of this report.
 
Allowance for Doubtful Accounts
 
We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends, economic conditions, age of receivables and other information. Higher customer bills due to increased electricity and gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2008 and 2007. We believe the allowance for doubtful accounts is based on reasonable estimates. As part of the 2005 gas rate order for MichCon, the MPSC provided for the establishment of an uncollectible accounts tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. Detroit Edison has requested a similar tracking mechanism in its rate request filed January 26, 2009. However, failure to make continued progress in collecting our past due receivables in light of volatile energy prices and deteriorating economic conditions would unfavorably affect operating results and cash flow.
 
Asset Impairments
 
Goodwill
 
Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing these impairment tests, we estimate the reporting unit’s fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.
 
As of December 31, 2008, our goodwill totaled $2 billion with 97 percent of this amount allocated to our utility reporting units. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment.
 
We performed our annual impairment test on October 1, 2008 and determined that the estimated fair value of our reporting units exceeded their carrying value and no impairment existed. During the fourth quarter of 2008, the closing price of DTE Energy’s stock declined by approximately 11% and at December 31, 2008


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was approximately 3 percent below its book value per share. The market price of an individual equity security (and therefore the market capitalization of an entity with publicly traded equity securities) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over an entity. An acquirer is often willing to pay more for equity securities that give it a controlling interest (i.e. a control premium) than an investor would pay for a number of equity securities representing less than a controlling interest. That control premium may cause the fair value of the entity to exceed its market capitalization. In assessing whether the recent modest decline in the trading price of DTE Energy’s common stock below its book value was an indication of impairment, we considered the following factors: (1) the relatively short duration and modest decline in the trading price of DTE Energy’s common stock; (2) the impact of the national and regional recession on DTE Energy’s future operating results and anticipated cash flows; (3) the favorable results of the recently performed annual impairment test and (4) a comparison of book value to the traded market price, including the impact of a control premium. The implied control premium of approximately 3 percent needed to equate DTE Energy’s market price to its book value was below the low end of the range of control premiums observed in recent transactions. As a result of this assessment, we determined that the decline in market price did not represent a trigger event at December 31, 2008 and an updated impairment test was not performed.
 
We will continue to monitor our estimates and assumptions regarding future cash flows. While we believe our assumptions are reasonable, actual results may differ from our projections.
 
Long-Lived Assets
 
We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, condition of the asset, or plans to dispose of the asset before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. See Note 4 of Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Our Power and Industrial Projects segment has long-term contracts with General Motors Corporation (GM) and Ford Motor Company (Ford) to provide onsite energy services at certain of their facilities. At December 31, 2008, the book value of long-lived assets used in the servicing of these facilities was approximately $85 million. In addition, we have an equity investment of approximately $40 million in an entity which provides similar services to Chrysler LLC (Chrysler). These companies are in financial distress, with GM and Chrysler recently receiving loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. We consider the recent announcements by these companies as an indication of possible impairment due to a significant adverse change in the business climate that could affect the value of our long-lived assets as described in SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” and have performed an impairment test on these assets. Based on our current undiscounted cash flow projections we have determined that we do not have an impairment as of December 31, 2008. We have also determined that we do not have an other than temporary decline in our Chrysler-related equity investment as described in APB 18, “The Equity Method of Accounting for Investments in Common Stock.” As the circumstances surrounding the long-term viability of these entities are dynamic and uncertain, we continue to monitor developments as they occur and will update our impairment analyses accordingly.


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Pension and Postretirement Costs
 
We sponsor defined benefit pension plans and postretirement benefit plans for substantially all of the employees of the Company. The measurement of the plan obligations and cost of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. When determining the various assumptions that are required, we consider historical information as well as future expectations. The benefit costs are affected by, among other things, the actual rate of return on plan assets, the long-term expected return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the anticipated rate of increase of health care costs and the level of benefits provided to employees and retirees. Pension and postretirement benefit costs attributed to the segments are included with labor costs and ultimately allocated to projects within the segments, some of which are capitalized.
 
We had pension costs for pension plans of $24 million in 2008, $76 million in 2007, and $134 million in 2006. Postretirement benefits costs for all plans were $142 million in 2008, $188 million in 2007 and $197 million in 2006. Pension and postretirement benefits costs for 2008 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.75%. In developing our expected long-term rate of return assumption, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity, bond and other markets. Our 2009 expected long-term rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 55% in equity markets, 20% in fixed income markets, and 25% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we believe that 8.75% is a reasonable long-term rate of return on our plan assets for 2009. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.
 
We calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” allow the MRV of plan assets to be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For our pension plans, we use a calculated value when determining the MRV of the pension plan assets and recognize changes in fair value over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recorded. Volatile financial markets contributed to our investment performance resulting in unrecognized net losses. As of December 31, 2008, we had $1.1 billion of cumulative losses that remain to be recognized in the calculation of the MRV of pension assets. For our postretirement benefit plans, we use fair value when determining the MRV of postretirement benefit plan assets, therefore all investment losses and gains have been recognized in the calculation of MRV for these plans.
 
The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected plan pension and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis increased from 6.5% at December 31, 2007 to 6.9% at December 31, 2008. Due to the combination of recent company contributions, losses on plan assets due to negative financial market performance and higher discount rates, we estimate that our 2009 total pension costs will approximate $57 million compared to $24 million in 2008 and our 2009 postretirement benefit costs will approximate $208 million compared to $142 million in 2008. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. The pension cost tracking mechanism, implemented in November 2004, that provided for recovery or refunding of pension costs above or below amounts reflected in Detroit Edison’s base rates, at the request of Detroit Edison was not reauthorized by the MPSC in its rate order effective January 1, 2009. In April 2005,


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the MPSC approved the deferral of the non-capitalized portion of MichCon’s negative pension expense. MichCon will record a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.
 
Lowering the expected long-term rate of return on our plan assets by one-percentage-point would have increased our 2008 pension costs by approximately $39 million. Lowering the discount rate and the salary increase assumptions by one-percentage-point would have increased our 2008 pension costs by approximately $37 million. Lowering the health care cost trend assumptions by one-percentage-point would have decreased our postretirement benefit service and interest costs for 2008 by approximately $26 million.
 
At December 31, 2006, we adopted SFAS No. 158 and recognized the underfunded status of our pension and other postretirement plans. The impact of the adoption of SFAS No. 158 was an increase in pension and postretirement benefit liabilities of approximately $1.3 billion in 2006. We requested and received agreement from the MPSC to record the additional liability amounts for the Detroit Edison and MichCon benefit plans on the Statement of Financial Position as a regulatory asset. As a result, regulatory assets were increased by approximately $1.2 billion. The remainder of the increase in pension and postretirement benefit liabilities is included in accumulated other comprehensive loss, net of tax. In 2008, as required by SFAS 158, we changed the measurement date of our pension and postretirement benefit plans from November 30 to December 31. As a result we recognized adjustments of $17 million ($9 million after-tax) and $4 million to retained earnings and regulatory liabilities, respectively, which represents approximately one month of pension and other postretirement benefit cost for the period from December 1, 2007 to December 31, 2008.
 
The market value of our pension and postretirement benefit plan assets has been affected in a negative manner by the financial markets. The value of our plan assets was $3.8 billion at November 30, 2007 and $2.8 billion at December 31, 2008. At December 31, 2008 our pension plans were underfunded by $877 million and our other postretirement benefit plans were underfunded by $1.4 billion, reflected in noncurrent assets, current liabilities, and noncurrent liabilities, respectively. The decline relative to 2007 funding levels results from negative investment performance returns in 2008.
 
Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made contributions to our pension plans of $100 million and $150 million in 2008 and 2007, respectively. Also, we contributed $50 million to our pension plans in January 2009. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making up to a $250 million contribution to our pension plans in 2009 and up to $1.1 billion over the next five years. We made postretirement benefit plan contributions of $116 million and $76 million in 2008 and 2007, respectively. In January 2009, we contributed $40 million to our postretirement benefit plans. We are required by orders issued by the MPSC to make postretirement benefit contributions at least equal to the amounts included in Detroit Edison’s and MichCon’s base rates. As a result, we expect to make up to a $130 million contribution to our postretirement plans in 2009 and, subject to MPSC funding requirements, up to $750 million over the next five years.
 
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $14 million in 2008, $16 million in 2007, and $17 million in 2006.
 
See Note 18 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Legal Reserves
 
We are involved in various legal proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against us.


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Insured and Uninsured Risks
 
Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage - $10 million, general liability — $7 million, workers’ compensation — $9 million, and auto liability — $7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2008, this IBNR liability was approximately $39 million.
 
Accounting for Tax Obligations
 
We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement in accordance with FIN 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We also have non-income tax obligations related to property, sales and use and employment-related taxes and ongoing appeals related to these tax matters that are outside the scope of FIN 48 and accounted for under SFAS No. 5 and FASB Statement of Financial Accounting Concepts No. 6.
 
Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess our ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. We do not record valuation allowances for deferred tax assets related to capital losses that we believe will be realized in future periods. While we believe the resulting tax reserve balances as of December 31, 2008 and December 31, 2007 are appropriately accounted for in accordance with FIN 48, SFAS No. 5, SFAS No. 109 and FASB Statement of Financial Accounting Concepts No. 6, as applicable, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material. See Note 8 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
ENVIRONMENTAL MATTERS
 
Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which DTE or its subsidiaries, including Detroit Edison and MichCon are responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the time of the remediation work, changes in technology, regulations and the requirements of local governmental authorities. These matters, if resolved in a manner different from the estimates, could have a material effect on our results of operation and financial position, to the extent the costs are not recovered through the base rates set for our utilities. See Note 17 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
NEW ACCOUNTING PRONOUNCEMENTS
 
See Note 2 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


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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 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
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 Derivative assets or liabilities, 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. The fair value of derivative contracts are determined from a combination of quoted market prices, published indexes and mathematical valuation models. Where possible, we 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. Valuation models require various inputs, including forward prices, volatility, interest rates and exercise periods. For those inputs which are not observable, we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes, current market transactions or other observable market information may require us to record gains or losses at inception of new derivative contracts. Our credit risk and the credit risk of our counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the year ended December 31, 2008.
 
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 include proprietary gas inventory, certain gas storage and transportation arrangements, and gas and oil reserves.
 
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).


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The subsequent tables contain the following four categories represented by their operating characteristics and key risks:
 
  •  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.
 
  •  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.
 
  •  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.
 
  •  Other — Primarily represents derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, 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.
 
As a result of adherence to generally accepted accounting principles, the tables below do not include the expected earnings impacts of certain non-derivative gas storage, transportation 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 following tables provide details on changes in our MTM net asset (or liability) position during 2008:
 
                                         
    Economic
    Structured
    Proprietary
             
    Hedges     Contracts     Trading     Other     Total  
    (In millions)  
 
MTM at December 31, 2007
  $ 4     $ (365 )   $ 8     $ 2     $ (351 )
                                         
Reclassify to realized upon settlement
    (17 )     47       11       (2 )     39  
Changes in fair value recorded to income
    34       89       20       1       144  
Changes in fair value recorded in regulatory liabilities
                      2       2  
Amortization of option premiums
          (1 )     (1 )           (2 )
                                         
Amounts recorded to income
    17       135       30       1       183  
Cumulative effect adjustment to initially apply SFAS No. 157, pre-tax
          7                   7  
Amounts recorded in other comprehensive income
                      6       6  
Change in collateral held by (for) others
    (3 )     (7 )     (6 )           (16 )
Option premiums paid and other
          8       (10 )           (2 )
                                         
MTM at December 31, 2008
  $ 18     $ (222 )   $ 22     $ 9     $ (173 )
                                         
 
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.


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The following table provides a current and noncurrent analysis of Derivative assets and liabilities, as reflected on the Consolidated Statements of Financial Position as of December 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.
 
                                                 
    Economic
    Structured
    Proprietary
                Assets
 
    Hedges     Contracts     Trading     Eliminations     Other     (Liabilities)  
    (In millions)  
 
Current assets
  $ 36     $ 165     $ 116     $ (9 )   $ 8     $ 316  
Noncurrent assets
    8       129       3       (1 )     1       140  
                                                 
Total MTM assets
    44       294       119       (10 )     9       456  
                                                 
Current liabilities
    (15 )     (209 )     (70 )     9             (285 )
Noncurrent liabilities
    (11 )     (307 )     (27 )     1             (344 )
                                                 
Total MTM liabilities
    (26 )     (516 )     (97 )     10             (629 )
                                                 
Total MTM net assets (liabilities)
  $ 18     $ (222 )   $ 22     $     $ 9     $ (173 )
                                                 
 
The table below shows the maturity of our MTM positions:
 
                                         
                      2012
       
                      and
    Total Fair
 
Source of Fair Value
  2009     2010     2011     Beyond     Value  
    (In millions)  
 
Economic Hedges
  $ 21     $ (7 )   $ (2 )   $ 6     $ 18  
Structured Contracts
    (45 )     (64 )     (44 )     (69 )     (222 )
Proprietary Trading
    46       (24 )                 22  
Other
    9                         9  
                                         
Total
  $ 31     $ (95 )   $ (46 )   $ (63 )   $ (173 )
                                         
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
Market 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 conjunction 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. However, the Company does not bear significant exposure to earnings risk as such changes are included in regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms (see Note 1 of the Notes to Consolidated Financial Statements in Item 8 of this Report) and tracking mechanisms to mitigate some losses from customer migration due to electric Customer Choice programs and uncollectible accounts receivable at MichCon. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.
 
Our Power and Industrial Projects business segment is subject to crude oil, electricity, natural gas, coal and coal-based product price risk and other risks associated with the weakened U.S. economy including constricted capital and credit markets. To the extent that commodity price risk has not been mitigated through the use of long-term contracts, we manage this exposure using forward energy, capacity and futures contracts.


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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 may use forward energy and futures contracts.
 
Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign currency price fluctuations. These risks are managed by our energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.
 
Our Gas Midstream business segment has limited exposure to natural gas price fluctuations. 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 may have a material effect on our financial statements.
 
Our utilities and certain non-utility businesses provide services to the domestic automotive industry, including GM, Ford and Chrysler and many of their vendors and suppliers. GM and Chrysler have recently received loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. In February 2009, GM and Chrysler submitted viability plans to the U.S. Government indicating that additional loans were necessary to continue operations in the short term. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on our results, particularly in our Electric Utility and Power and Industrial Projects segments. As the circumstances surrounding the viability of these entities are dynamic and uncertain, we continue to monitor developments as they occur.
 
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.
 
Trading Activities
 
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


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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 December 31, 2008:
 
                         
    Credit Exposure
             
    before Cash
    Cash
    Net Credit
 
    Collateral     Collateral     Exposure  
    (In millions)  
 
Investment Grade(1)
                       
A- and Greater
  $ 314     $ (14 )   $ 300  
BBB+ and BBB
    253             253  
BBB-
    47             47  
                         
Total Investment Grade
    614       (14 )     600  
Non-investment grade(2)
    25       (1 )     24  
Internally Rated — investment grade(3)
    206       (2 )     204  
Internally Rated — non-investment grade(4)
    28       (4 )     24  
                         
Total
  $ 873     $ (21 )   $ 852  
                         
 
 
(1) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 22 percent of the total gross credit exposure.
 
(2) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented approximately two percent of the total gross credit exposure.
 
(3) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 17 percent of the total gross credit exposure.
 
(4) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately three percent of the total gross credit exposure.
 
Interest Rate Risk
 
DTE Energy is 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 December 31, 2008, we had a floating rate debt-to-total debt ratio of approximately 12% (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


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forward rates at December 31, 2008 by a hypothetical 10% and calculating the resulting change in the fair values.
 
The results of the sensitivity analysis calculations follow:
 
                     
    Assuming a 10%
  Assuming a 10%
   
Activity
  increase in rates   decrease in rates   Change in the fair value of
    (In millions)
 
Coal Contracts
  $ 1     $ (1 )   Commodity contracts
Gas Contracts
  $ (13 )   $ 13     Commodity contracts
Oil Contracts
  $ 1     $ (1 )   Commodity contracts
Power Contracts
  $ 3     $ (2 )   Commodity contracts
Interest Rate Risk
  $ (317 )   $ 346     Long-term debt
Foreign Currency Risk
  $ 5     $ (5 )   Forward contracts
Discount Rates
  $ 1     $ (1 )   Commodity contracts


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Item 8.   Financial Statements and Supplementary Data
 
The following consolidated financial statements and schedules are included herein.
 
         
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Controls and Procedures
 
(a)   Evaluation of disclosure controls and procedures
 
Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 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 providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.
 
(b)   Management’s report on internal control over financial reporting
 
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
 
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of the effectiveness to future periods are subject to the risks that a control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that, as of December 31, 2008, the Company’s internal control over financial reporting was effective based on those criteria.
 
The Company’s independent registered public accounting firm that audited the financial statements included in this annual report has issued an attestation report on the Company’s internal control over financial reporting.
 
(c)   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 December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of DTE Energy Company:
 
We have audited the consolidated statements of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, cash flows, and changes in shareholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy Company and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, present fairly, in all material respects, the information set forth therein.
 
As discussed in Note 8 to the consolidated financial statements, in connection with the required adoption of a new accounting standard, the Company changed its method of accounting for uncertainty in income taxes on January 1, 2007. As discussed in Notes 18 and 19 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans and share based payments, respectively.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.
 
/s/  DELOITTE & TOUCHE LLP
 
Detroit, Michigan
February 27, 2009


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of DTE Energy Company:
 
We have audited the internal control over financial reporting of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2008 of the Company and our report dated February 27, 2009 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
 
/s/  DELOITTE & TOUCHE LLP
 
Detroit, Michigan
February 27, 2009


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DTE Energy Company
Consolidated Statements of Operations
 
                         
    Year Ended December 31  
    2008     2007     2006  
    (In millions, Except per share amounts)  
 
Operating Revenues
  $ 9,329     $ 8,475     $ 8,157  
                         
Operating Expenses
                       
Fuel, purchased power and gas
    4,306       3,552       3,047  
Operation and maintenance
    2,694       2,892       2,677  
Depreciation, depletion and amortization
    901       932       990  
Taxes other than income
    304       357       309  
Gain on sale of non-utility business
    (128 )     (900 )      
Other asset (gains) and losses, reserves and impairments, net
    (11 )     37       67  
                         
      8,066       6,870       7,090  
                         
Operating Income
    1,263       1,605       1,067  
                         
Other (Income) and Deductions
                       
Interest expense
    503       533       525  
Interest income
    (19 )     (25 )     (26 )
Other income
    (104 )     (93 )     (61 )
Other expenses
    64       35       93  
                         
      444       450       531  
                         
Income Before Income Taxes and Minority Interest
    819       1,155       536  
Income Tax Provision
    288       364       146  
Minority Interest
    5       4       1  
                         
Income from Continuing Operations
    526       787       389  
Discontinued Operations
                       
Income (Loss) from discontinued operations, net of tax
    22       (4 )     (208 )
Minority interest in discontinued operations
    2       (188 )     (251 )
                         
      20       184       43  
Cumulative Effect of Accounting Changes, net of tax
                1  
                         
Net Income
  $ 546     $ 971     $ 433  
                         
Basic Earnings per Common Share
                       
Income from continuing operations
  $ 3.24     $ 4.64     $ 2.19  
Discontinued operations
    .13       1.09       .24  
Cumulative effect of accounting changes
                .01  
                         
Total
  $ 3.37     $ 5.73     $ 2.44  
                         
Diluted Earnings per Common Share
                       
Income from continuing operations
  $ 3.23     $ 4.62     $ 2.18  
Discontinued operations
    .13       1.08       .24  
Cumulative effect of accounting changes
                .01  
                         
Total
  $ 3.36     $ 5.70     $ 2.43  
                         
Weighted Average Common Shares Outstanding
                       
Basic
    162       169       177  
Diluted
    163       170       178  
Dividends Declared per Common Share
  $ 2.12     $ 2.12     $ 2.075  
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
Consolidated Statements of Financial Position
 
                 
    December 31  
    2008     2007  
    (In millions)  
 
ASSETS
Current Assets
               
Cash and cash equivalents
  $ 86     $ 123  
Restricted cash
    86       140  
Accounts receivable (less allowance for doubtful accounts of $265 and $182, respectively)
               
Customer
    1,666       1,658  
Other
    166       514  
Accrued power and gas supply cost recovery revenue
    22       76  
Inventories
               
Fuel and gas
    333       429  
Materials and supplies
    206       204  
Deferred income taxes
    227       387  
Derivative assets
    316       181  
Other
    220       196  
Current assets held for sale
          83  
                 
      3,328       3,991  
                 
Investments
               
Nuclear decommissioning trust funds
    685       824  
Other
    595       446  
                 
      1,280       1,270  
                 
Property
               
Property, plant and equipment
    20,065       18,809  
Less accumulated depreciation and depletion
    (7,834 )     (7,401 )
                 
      12,231       11,408  
                 
Other Assets
               
Goodwill
    2,037       2,037  
Regulatory assets
    4,231       2,786  
Securitized regulatory assets
    1,001       1,124  
Intangible assets
    70       25  
Notes receivable
    115       87  
Derivative assets
    140       199  
Prepaid pension assets
          152  
Other
    157       116  
Noncurrent assets held for sale
          547