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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Form 10-K
 
     
  þ  
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
     
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number 1-11607
 
 
 
 
DTE ENERGY COMPANY
(Exact name of registrant as specified in its charter)
 
     
Michigan
  38-3217752
(State or other jurisdiction of
incorporation or organization)
  (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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).  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. þ.
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
On June 30, 2009, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $5.3 billion (based on the New York Stock Exchange closing price on such date). There were 165,633,622 shares of common stock outstanding at January 31, 2010.
 
Certain information in DTE Energy Company’s definitive Proxy Statement for its 2010 Annual Meeting of Common Shareholders to be held May 6, 2010, 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, 2009

TABLE OF CONTENTS
 
                 
        Page
 
DEFINITIONS     2  
Forward -Looking Statements     4  
PART I
  Items 1., 1A., 1B. & 2.     Business, Risk Factors, Unresolved Staff Comments and Properties     6  
  Item 3.     Legal Proceedings     26  
  Item 4.     Submission of Matters to a Vote of Security Holders     27  
PART II
  Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     27  
  Item 6.     Selected Financial Data     30  
  Item 7.     Management’s Discussion And Analysis of Financial Condition and Results of Operations     31  
  Item 7A.     Quantitative and Qualitative Disclosures About Market Risk     59  
  Item 8.     Financial Statements and Supplementary Data     63  
  Item 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     140  
  Item 9A.     Controls and Procedures     140  
  Item 9B.     Other Information     140  
PART III
  Item 10.     Directors, Executive Officers and Corporate Governance     140  
  Item 11.     Executive Compensation     140  
  Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     140  
  Item 13.     Certain Relationships and Related Transactions, and Director Independence     140  
  Item 14.     Principal Accountant Fees and Services     140  
 
PART IV
  Item 15.     Exhibits and Financial Statement Schedules     140  
Signatures     152  
 EX-12.45
 EX-21.5
 EX-23.22
 EX-23.23
 EX-31.55
 EX-31.56
 EX-32.55
 EX-32.56
 EX-99.49
 EX-99.50
 EX-99.51
 EX-99.52
 EX-99.53
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT


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DEFINITIONS
 
     
ASC
  Accounting Standards Codification
ASU
  Accounting Standards Update
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
FSP
  FASB Staff Position
FTRs
  Financial transmission rights
GCR
  A gas cost recovery mechanism authorized by the MPSC that allows MichCon to recover through rates its natural gas costs.
ISO-NE
  ISO New England Inc. is a Regional Transmission Organization serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
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 is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.
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
NYMEX
  New York Mercantile Exchange
PJM
  PJM Interconnection LLC is a Regional Transmission Organization serving all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
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 costs.
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


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Subsidiaries
  The direct and indirect subsidiaries of DTE Energy Company
Synfuels
  The fuel produced through a process involving chemically modifying and binding particles of coal. 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 with respect to the financial condition, results of operations and business of DTE Energy. Forward-looking statements are subject to numerous assumptions, risks and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:
 
  •  the length and severity of ongoing economic decline resulting in lower demand, customer conservation and increased thefts of electricity and gas;
 
  •  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;
 
  •  economic climate and population growth or decline in the geographic areas where we do business;
 
  •  high levels of uncollectible accounts receivable;
 
  •  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;
 
  •  the timing and extent of changes in interest rates;
 
  •  the level of borrowings;
 
  •  potential for losses on investments, including nuclear decommissioning and benefit plan assets and the related increases in future expense and contributions;
 
  •  the potential for increased costs or delays in completion of significant construction projects;
 
  •  the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
 
  •  environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements that include or could include carbon and more stringent mercury emission controls, a renewable portfolio standard, energy efficiency mandates, a carbon tax or cap and trade structure and ash landfill regulations;
 
  •  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;
 
  •  volatility in the short-term natural gas storage markets impacting third-party storage revenues;
 
  •  cost reduction efforts and the maximization of plant and distribution system performance;
 
  •  the effects of competition;
 
  •  the uncertainties of successful exploration of gas shale resources and challenges in estimating 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;


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  •  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 amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
 
  •  the cost of protecting assets against, or damage due to, terrorism or cyber attacks;
 
  •  the availability, cost, coverage and terms of insurance and stability of insurance providers;
 
  •  changes in and application of accounting standards and financial reporting regulations;
 
  •  changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues; 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 other 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 2.1 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, gathering, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan.
 
Our other 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 24 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
 
  •  The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million residential, commercial and industrial customers in southeastern Michigan.
 
Gas Utility
 
  •  The 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,


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  commercial and industrial customers throughout Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.
 
Non-Utility Operations
 
  •  Gas Storage and Pipelines consists of natural gas pipelines and storage businesses.
 
  •  Unconventional Gas Production is engaged in unconventional gas project development and production.
 
  •  Power and Industrial Projects is comprised of coke batteries and pulverized coal projects, reduced emission fuel and steel industry fuel-related projects, on-site energy services, power generation and coal transportation and marketing.
 
  •  Energy Trading consists of energy marketing and trading operations.
 
Corporate & Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.
 
(FLOW 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 three major classes of customers: residential, commercial and industrial, principally throughout southeastern Michigan.


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Revenue by Service
 
                         
    2009     2008     2007  
    (in Millions)  
 
Residential
  $ 1,820     $ 1,726     $ 1,739  
Commercial
    1,702       1,753       1,723  
Industrial
    730       894       854  
Other
    299       289       384  
                         
Subtotal
    4,551       4,662       4,700  
Interconnection sales(1)
    163       212       200  
                         
Total Revenue
  $ 4,714     $ 4,874     $ 4,900  
                         
 
 
(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. 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 nine long-term and nine short-term contracts for a total purchase of approximately 28 million tons of low-sulfur western coal to be delivered from 2010 through 2012. We also have nine long-term and two short-term contracts for the purchase of approximately 9 million tons of Appalachian coal to be delivered from 2010 through 2012. All of these contracts have fixed prices. We have approximately 87% of our 2010 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 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, 2009 are as follows:
 
                         
        Summer Net
     
    Location by
  Rated
     
    Michigan
  Capability(1)      
Plant Name
  County  
(MW)
   
(%)
   
Year in Service
Fossil-fueled Steam-Electric
                       
Belle River(2)
  St. Clair     1,034       9.3     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(3)
  Monroe     3,090       27.9     1971, 1973 and 1974
River Rouge
  Wayne     523       4.7     1957 and 1958
St. Clair(4)
  St. Clair     1,365       12.3     1953, 1954, 1959, 1961 and 1969
Trenton Channel
  Wayne     730       6.6     1949 and 1968
                         
          7,944       71.7      
Oil or Gas-fueled Peaking Units
  Various     1,101       10.0     1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2(5)
  Monroe     1,102       10.0     1988
Hydroelectric Pumped Storage Ludington(6)
  Mason     917       8.3     1973
                         
          11,064       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) The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
(3) The Monroe power plant provided 38% of Detroit Edison’s total 2009 power generation.
 
(4) Excludes one oil-fueled unit (250 MW) in cold standby status.
 
(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 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
Detroit Edison owns and operates 677 distribution substations with a capacity of approximately 33,347,000 kilovolt-amperes (kVA) and approximately 423,600 line transformers with a capacity of approximately 21,883,000 kVA.
 
Circuit miles of electric distribution lines owned and in service as of December 31, 2009:
 
                 
    Circuit Miles  
Operating Voltage-Kilovolts (kV)
  Overhead     Underground  
 
4.8 kV to 13.2 kV
    28,243       13,884  
24 kV
    177       681  
40 kV
    2,317       363  
120 kV
    54       13  
                 
      30,791       14,941  
                 


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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 Notes 4, 9, 12 and 20 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. We expect to minimize the impacts of declines in average customer usage through regulatory mechanisms which will partially decouple our revenue levels from sales volumes.
 
The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services, subject to limits. Customers choosing to purchase power from alternative electric suppliers represented approximately 3% of retail sales in 2009 and 2008, and 4% of such sales in 2007. 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% cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer Choice on our financial performance. We expect that in 2010 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales. When market conditions are favorable, we sell power into the wholesale market, in order to lower costs to full-service customers.


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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.
 
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
 
                         
    2009     2008     2007  
    (in Millions)  
 
Gas sales
  $ 1,443     $ 1,824     $ 1,536  
End user transportation
    144       143       140  
Intermediate transportation
    69       73       59  
Storage and other
    132       112       140  
                         
Total Revenue
  $ 1,788     $ 2,152     $ 1,875  
                         
 
  •  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 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 2.6 Bcf, with approximately 67% of the volume coming from underground storage for 2009. 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.


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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.
 
We are directly connected to interstate pipelines, providing access to most of the major natural gas supply producing regions in the Gulf Coast, Mid-Continent and Canadian regions. Our primary long-term transportation supply contracts are as follows:
 
                 
    Availability
    Contract
 
    (MMcf/d)     Expiration  
 
TransCanada PipeLines Limited
    53       2010  
Great Lakes Gas Transmission L.P. 
    30       2010  
Vector Pipeline L.P. 
    50       2012  
ANR Pipeline Company
    245       2013  
Viking Gas Transmission Company
    51       2013  
Panhandle Eastern Pipeline Company
    75       2029  
 
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 1,177,000 service lines and approximately 1,312,000 active meters. We own approximately 2,100 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 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 own 666 miles of transportation and gathering (non-utility) pipelines in the northern lower peninsula of Michigan. We lease a portion of our pipeline system to the Vector Pipeline Partnership (an affiliate) through a capital-lease arrangement. See Note 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Regulation
 
MichCon’s business is 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. MichCon operates natural gas transportation and storage facilities in Michigan as intrastate facilities regulated by the MPSC and provides intrastate transportation and storage services pursuant to an MPSC-approved tariff. MichCon also provides interstate transportation and storage services in accordance with an Operating Statement on file with the FERC. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
 
See Note 12 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.


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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 expect to minimize the impacts of declines in usage through regulatory mechanisms we have requested in our current rate case, which will partially decouple our revenue levels from sales volumes. 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 Midwestern 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.
 
GAS STORAGE AND PIPELINES
 
Description
 
Gas Storage and Pipelines 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 90 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 markets.
 
Our customers include various utilities, pipelines, and producers and marketers.


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Properties
 
The Gas Storage and Pipelines business holds the following property:
 
                 
Property Classification
  % Owned    
Description
 
Location
 
Pipelines
               
Vector Pipeline
    40 %   348-mile pipeline with 1,300 MMcf per day capacity   IN, IL, MI & Ontario
Millennium Pipeline
    26 %   182-mile pipeline with 525 MMcf per day capacity   New York
Storage
               
Washington 10 (includes Shelby 2 Storage)
    100 %   74 Bcf of storage capacity   MI
Washington 28
    50 %   16 Bcf of storage capacity   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.
 
Regulation
 
The Gas Storage and Pipelines business operates natural gas storage facilities in Michigan as intrastate facilities regulated by the MPSC and provides intrastate storage and related services pursuant to an MPSC-approved tariff. We also provide interstate services in accordance with an Operating Statement on file with the FERC. Vector and Millennium Pipelines provide interstate transportation services in accordance with their FERC-approved tariffs.
 
Strategy and Competition
 
Our Gas Storage and Pipelines business expects to continue its steady growth plan by expanding existing assets and developing new assets that are typically supported with long-term customer commitments. The Gas Storage and Pipelines 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. In 2009, we completed the Shelby 2 storage field at our Washington 10 storage complex which increased the capacity by 3 Bcf. Also in 2009, Vector Pipeline completed its Athens, Michigan Compressor Station expansion which increased its long-haul capacity by approximately 100 MMcf/d to 1.3 Bcf/d. Due to the proximity of the Millennium Pipeline to the Marcellus Shale in Southern New York/Northern Pennsylvania, we anticipate that the Millennium Pipeline may have opportunities to expand in the future.
 
UNCONVENTIONAL GAS PRODUCTION
 
Description
 
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas.
 
In 2009, we added proved reserves of 67 Bcfe resulting in year-end total proved reserves of 234 Bcfe. The Barnett shale wells yielded 5 Bcfe of production in 2009. Barnett shale leasehold acres increased to 69,272 gross acres (63,367 net of interest of others) excluding impairments. Due to economic conditions and


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low natural gas prices during the year, we chose to do minimal lease acquisitions and reduce the number of new wells. We drilled a total of 11 wells in the Barnett shale acreage in 2009.
 
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 based on prevailing market prices.
 
Properties and Other
 
The following information pertains to our interests in the Barnett shale as of December 31:
 
                         
    2009     2008     2007  
 
Producing Wells(1)(2)(3)
    168       155       120  
Developed Lease Acreage(1)(3)(4)
    14,968       14,248       9,880  
Undeveloped Lease Acreage(1)(3)(5)
    48,399       46,187       38,066  
Production Volume (Bcfe)
    5.0       5.0       3.0  
Proved Reserves (Bcfe)(6)
    234       167       144  
Capital Expenditures (in millions)(3)
  $ 26     $ 100     $ 89  
Future Undiscounted Cash Flows (in millions)(7)
  $ 392     $ 324     $ 521  
Average Gas Price, excluding hedge contracts (per Mcf)
  $ 4.34     $ 8.69     $ 6.29  
 
 
(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.
 
(6) The increase in proved reserves in 2009 is primarily due to a definitional change in the disclosure rule issued by the SEC and technological improvements.
 
(7) 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.
 
Strategy and Competition
 
We manage and operate our properties to maximize returns on investment and increase earnings. We continue to develop our holdings in the western portion of the Barnett shale and seek opportunities for acquisitions or divestitures of select properties within our asset base, when conditions are appropriate. Competitive pressures in the Barnett shale have decreased due to lower commodity prices resulting in reduced investment by industry participants. This downward pressure has created opportunities for us to reduce operating expenses and grow at lower cost than in prior periods.


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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, 2009 related to Barnett shale production:
 
         
    2010
 
Long-term fixed price obligations
       
Volume (Bcf)
    1.2  
Price (per Mcf)
  $ 7.16  
 
In 2010, we expect to drill approximately 10 to 15 wells in the Barnett shale. Investment for the area is expected to be approximately $25 million during 2010.
 
POWER AND INDUSTRIAL PROJECTS
 
Description
 
Power and Industrial Projects is comprised primarily of projects that deliver energy 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 services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries.
 
Products and services include pulverized coal and petroleum coke supply, metallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment, compressed air supply and reduced emission fuel. We own and operate one gas-fired peaking electric generating plant, two biomass-fired electric generating plants and own one coal-fired power plant. Two additional biomass-fired electric generating plants are currently under development pending certain regulatory approvals with expected in-service dates of August 2010 and March 2013. Production tax credits related to two of the coke battery facilities expired on December 31, 2009.
 
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.
 
We deliver reduced emission fuel to utilities with coal-fired electric generation power plants. We own and operate five facilities that process raw coal into reduced emission fuel resulting in significant reductions in Nitrogen Oxide (NO), Sulfur Dioxide (SO2), and Mercury (Hg) emissions. Production tax credits are expected to be generated by these facilities beginning in 2010 and continuing for ten years upon achieving certain criteria, including entering into transactions with unrelated equity partners or third-party customers for the reduced emission fuel. We expect to reduce our ownership interests in these facilities in 2010. We are investors in steel industry fuel entities which sell steel industry fuel to unrelated parties at three coke battery sites. Steel industry fuels facilities recycle tar decanter sludge, a byproduct of the coking process. Tax credits were generated in 2009 and we expect to generate additional credits in 2010. The ability to generate tax credits from the steel industry fuel process expires at the end of 2010.


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Properties and Other
 
The following are significant properties operated by the Power and Industrial projects segment:
 
         
Facility
 
Location
 
Service Type
 
Steel
       
Pulverized Coal Operations
  MI & MD   Pulverized Coal
Coke Production
  MI, PA & IN   Metallurgical Coke Supply/Steel Industry Fuels
Other Investment in Coke Production
  IN   Metallurgical Coke Supply/Steel Industry Fuels
On-Site Energy
       
Automotive
  Various sites in
MI, IN, OH, NY & PA
  Electric Distribution, Chilled Water, Waste Water, Steam, Cooling Tower Water, Reverse Osmosis Water, Compressed Air, Mist and Dust Collectors, Steam and Chilled Water
Airports
  MI & PA   Electricity, Hot and Chilled Water
Power & Renewables
       
Pulp and Paper
  AL   Electric Generation and Steam
Power Generation
  MI   Natural Gas
Other Industries
       
Reduced Emission Fuel
  MI   Reduced Emission Fuel Supply
Coal Terminaling
  IL   Coal Terminal and Blending
Pulverized PetCoke
  MS   Pulverized Petroleum Coke
Landfill Gas Recovery
  Various U.S. Sites   Landfill Gas Production
 
Landfill Gas Recovery
 
                         
    2009   2008   2007
 
Landfill Sites
    23       23       28  
Gas Produced (in Bcf)
    19.6       18.6       23.5  
 
Coal Transportation and Marketing
 
                         
    2009   2008   2007
    (in Millions)
 
Tons of Coal Shipped(1)
    20       18       35  
 
 
(1) Includes intercompany transactions of 1 million, 2 million, and 19 million tons in 2009, 2008, and 2007, respectively, primarily related to synfuel operations in 2007.
 
                         
    2009     2008     2007  
    (in Millions)  
 
Production Tax Credits Generated (Allocated to DTE Energy)
                       
Coke Battery(1)
  $ 5     $ 5     $ 5  
Steel Industry Fuels(2)
    4              
Power Generation
    2       2       2  
Landfill Gas Recovery
    1             3  
 
 
(1) Tax laws enabling production tax credits related to two coke battery facilities expired on December 31, 2009.
 
(2) IRS regulations enabling the steel industry fuel tax credits are scheduled to expire on December 31, 2010.


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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; landfill gas recovery; and reduced emission fuel businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties. There are limited competitors for our existing disparate businesses who provide similar products and services.
 
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. 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:
 
  •  Acquiring and developing landfill gas recovery facilities, renewable energy projects, and other energy projects qualifying for tax credits; and
 
  •  Providing operating services to owners of industrial and power plants.
 
After experiencing a weakened U.S. economy including constricted capital and credit markets, we expect a return to normal demand for our steel-related products in 2010 improving the financial performance of our coke battery and pulverized coal operations. In addition, our two primary automotive customers, General Motors and Chrysler, have emerged from bankruptcy and we continue providing onsite products and services. We will continue to monitor the steel and automotive industries closely during 2010.
 
Our Coal Transportation and Marketing business will continue to leverage its existing business in 2010. Trends such as carbon and greenhouse gas legislation, railroad and mining consolidation and the lack of certainty in developing new mines could have an impact on how we compete in the future. In 2011, our existing long-term rail transportation contract, which is at rates significantly below the current market, will expire and we anticipate a decrease in transportation-related revenue of approximately $120 million as a result. 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.
 
ENERGY TRADING
 
Description
 
Energy Trading focuses on physical and financial 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 in earnings 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 transmission and 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


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recognized in different accounting periods. We may incur mark-to-market gains or losses in one period that could reverse in subsequent periods.
 
Regulation
 
Energy Trading has market-based rate authority from the FERC to sell power and authority from FERC to sell natural gas at market prices. Energy Trading is subject to FERC reporting requirements and market behavior rules. Energy Trading also complies with position limits and reporting requirements related to financial trading set by the Commodity Futures Trading Commission.
 
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, financial institutions, traders, utilities and other energy providers. The trading business is dependent upon the availability of capital and an investment grade credit rating. The Company believes it has ample available capital capacity to support Energy Trading activities. We monitor our use of capital closely to ensure that our commitments do not exceed capacity. 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
 
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.
 
         
    2007  
    (in Millions)  
 
Production Tax Credits Generated
       
Allocated to DTE Energy
  $ 21  
Allocated to partners
    186  
         
    $ 207  
         
 
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


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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     Total  
    (in Millions)  
 
Air
  $ 2,200     $     $ 2,200  
Water
    55             55  
MGP sites
    5       36       41  
Other sites
    21       2       23  
                         
Estimated total future expenditures through 2019
  $ 2,281     $ 38     $ 2,319  
                         
Estimated 2010 expenditures
  $ 82     $ 5     $ 87  
                         
Estimated 2011 expenditures
  $ 253     $ 6     $ 259  
                         
 
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. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. It is not possible to quantify the impact of those expected rulemakings at this time.
 
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 completed studies and expected future studies, 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 and in April 2009 upheld EPA’s use of this provision in determining best available technology for reducing environmental impacts. Concurrently, the EPA continues to develop a revised rule, a draft of which is expected to be published by summer 2010. The EPA has also proposed an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.
 
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. Detroit Edison owns, or previously owned, three former MGP sites. In addition to the MGP sites, we are also in the process of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash storage facility, electrical distribution substations, gas pipelines, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years.
 
Landfill— Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction.
 
The EPA has expressed its intentions to develop new federal regulations for coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). A proposed regulation is expected in the first quarter of 2010. Among the options EPA is currently considering, is a ruling that may designate coal ash as a “Hazardous Waste” as defined by RCRA. However, agencies and legislatures have urged EPA to regulate coal ash as a non-hazardous waste. If EPA were to designate coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes.


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Some of the regulatory actions currently being contemplated could have a material adverse impact on our operations and financial position and the rates we charge our customers.
 
Global Climate Change — Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs to emit greenhouse gases. Despite action by the Senate Environmental and Public Works Committee to pass a similar but more stringent bill in October 2009, full Senate action on a climate bill is not expected before the spring of 2010. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures and the purchase of emission allowances from market sources. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify these impacts on DTE Energy or its customers at this time.
 
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. Our non-utility affiliates are substantially in compliance with all environmental requirements.
 
See Notes 12 and 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report and Management’s Discussion and Analysis in Item 7 of this Report.
 
EMPLOYEES
 
We had 10,244 employees as of December 31, 2009, of which 5,186 were represented by unions. The majority of our union employees are under contracts that expire in June and October 2010 and August 2012.
 
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 and steel industries which have undergone 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 below investment grade 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


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require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which could impact our liquidity.
 
Our ability to access capital markets is important.  Our ability to access capital markets is important to operate our businesses. In the past, 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 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 credit facilities that expire in 2010. 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 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 debt and equity 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 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. Energy trading activities take place in volatile markets and expose us to risks related to commodity price movements. We routinely have speculative trading positions in the market, within strict policy guidelines we set, resulting from the management of our business portfolio. To the extent speculative trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position. We manage our exposure by establishing and enforcing strict risk limits and risk management procedures. During periods of extreme volatility, these risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. As a result, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position.


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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 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. Our regulators also may decide to disallow recovery of certain costs in customers’ rates if they determine that those costs do not meet the standards for recovery under our governing laws and regulations. The State of Michigan will elect a new governor and legislature in 2010 and we cannot predict the outcome of that election. We cannot predict whether election results or changes in political conditions will affect the regulations or interpretations affecting our utilities. 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.
 
We may be required to refund amounts we collect under self-implemented rates.  Michigan law allows our utilities to self-implement rate changes six months after a rate filing, subject to certain limitations. However, if the final rate case order provides for lower rates than we have self-implemented, we must refund the difference, with interest. We have self-implemented rates in the past and have been ordered to make refunds to customers. Our financial performance may be negatively affected if the MPSC sets lower rates in future rate cases than those we have self-implemented, thereby requiring us to issue refunds. We cannot predict what rates an MPSC order will adopt in future rate cases.
 
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 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. 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.
 
Construction and capital improvements to our power facilities subject us to risk.  We are managing ongoing and planning future significant construction and capital improvement projects at multiple power


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generation and distribution facilities. Many factors that could cause delay or increased prices for these complex projects are beyond our control, including the cost of materials and labor, subcontractor performance, timing and issuance of necessary permits, construction disputes and weather conditions. Failure to complete these projects on schedule and on budget for any reason could adversely affect our financial performance and operations at the affected facilities.
 
The supply and/or price of energy commodities and/or related services 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 the amounts we charge our utility customers for electricity and on the profitability of our non-utility business. 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.
 
The supply and/or price other industrial raw and finished inputs and/or related services may impact our financial results.  We are dependent on supplies of certain commodities, such as copper and limestone, among others, and industrial materials and services in order to maintain day-to-day operations and maintenance of our facilities. Price fluctuations or supply interruptions for these commodities and other items could have a negative impact on the amounts we charge our customers for our utility products and on the profitability of 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 synfuel, coke production, landfill gas recovery, biomass fired electric generation, reduced emission fuel, steel industry fuel and gas production operations. We have received favorable private letter rulings on all of the synfuel facilities. All production tax credits taken after 2006 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


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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. We could be required to install expensive pollution control measures or limit or cease activities based on these regulations. Additionally, we may become a responsible party for environmental cleanup 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 and our unconventional gas production 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.
 
Renewable portfolio standards and energy efficiency programs may affect our business.  We are subject to Michigan and potential future federal legislation and regulation requiring us to secure sources of renewable energy. Under the current Michigan legislation we will be required in the future to provide a specified percentage of our power from Michigan renewable energy sources. We are developing a strategy for complying with the existing state legislation, but we do not know what requirements may be added by federal legislation. We are actively engaged in developing renewable energy projects and identifying third party projects in which we can invest. We cannot predict the financial impact or costs associated with these future projects.
 
We are also required by Michigan legislation to implement energy efficiency measures and provide energy efficiency customer awareness and education programs. These requirements necessitate expenditures and implementation of these programs creates the risk of reducing our revenues as customers decrease their energy usage. We do not know how these programs will impact our business and future operating results.
 
Threats of terrorism or cyber attacks could affect our business.  We may be threatened by problems such as computer viruses or terrorism that may disrupt our operations and could harm our operating results. Our industry requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes. If our information technology systems were to fail and we were unable to recover in a timely way, we might be unable to fulfill critical business functions, which could have a material adverse effect on our business, operating results, and financial condition.
 
In addition, our generation plants, gas pipeline and storage facilities and electrical distribution facilities in particular may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We have increased security as a result of past events and we may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict.
 
We may not be fully covered by insurance.  We have a comprehensive insurance program in place to provide coverage for various types of risks, including catastrophic damage as a result of acts of God, terrorism 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.
 
Failure to maintain the security of personally identifiable information could adversely affect us.  In connection with our business we collect and retain personally identifiable information of our customers,


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shareholders and employees. Our customers, shareholders and employees expect that we will adequately protect their personal information, and the United States regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or fraudulent use of customer, shareholder, employee or DTE Energy data by cybercrime or otherwise could adversely impact our reputation and could result in significant costs, fines and litigation.
 
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. Contracts with several of our unions, including our contract with our largest union, representing about 3,800 of our employees, expire on different dates throughout 2010. In addition, our contracts with unions representing two small groups of employees expired on December 31, 2009 and another union is currently negotiating its first contract. We cannot predict the outcome of any of these contract negotiations, some of which have not yet commenced. 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 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.
 
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. On October 15, 2009, the U.S. District Court granted defendants’ motions dismissing all of plaintiffs’ federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs’ state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.
 
In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and Title V operating permit requirements under the Clean Air Act. We believe that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA


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could bring legal action against Detroit Edison. We could also be required to install additional pollution control equipment at some or all of the power plants in question, engage in Supplemental Environmental Programs, and/or pay fines. We cannot predict the financial impact or outcome of this matter, or the timing of its resolution.
 
For additional discussion on legal matters, see Notes 12 and 20 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 2009.
 
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  
 
2009
                           
    First   $ 37.11     $ 23.32     $ 0.530  
    Second   $ 32.43     $ 27.32     $ 0.530  
    Third   $ 36.46     $ 30.59     $ 0.530  
    Fourth   $ 44.96     $ 33.75     $ 0.530  
2008
                           
    First   $ 45.34     $ 37.81     $ 0.530  
    Second   $ 44.82     $ 38.95     $ 0.530  
    Third   $ 44.97     $ 38.78     $ 0.530  
    Fourth   $ 40.92     $ 27.82     $ 0.530  
 
At December 31, 2009, there were 165,400,045 shares of our common stock outstanding. These shares were held by a total of 78,903 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 $347 million in 2009, $344 million in 2008, and $364 million in 2007. 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 14 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 22 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.


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See the following table for information as of December 31, 2009.
 
                         
    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
    5,593,392     $ 40.50       4,078,306  
 
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, 2009:
 
                                         
                Number
             
                of Shares
          Maximum Dollar
 
                Purchased as
          Value that May
 
          Average
    Part of Publicly
          Yet Be
 
    Number of
    Price
    Announced
    Average
    Purchased Under
 
    Shares
    Paid per
    Plans or
    Price Paid
    the Plans or
 
    Purchased(1)     Share(1)     Programs(2)     per Share(2)     Programs(2)  
 
01/01/09 — 01/31/09
                          $ 822,895,623  
02/01/09 — 02/28/09
                            822,895,623  
03/01/09 — 03/31/09
                            822,895,623  
04/01/09 — 04/30/09
                            822,895,623  
05/01/09 — 05/31/09
                            822,895,623  
06/01/09 — 06/30/09
                            822,895,623  
07/01/09 — 07/31/09
                            822,895,623  
08/01/09 — 08/31/09
    25,000     $ 35.01                   822,895,623  
09/01/09 — 09/30/09
                            822,895,623  
10/01/09 — 10/31/09
                            822,895,623  
11/01/09 — 11/30/09
                            822,895,623  
12/01/09 — 12/31/09
                             
                                         
Total
    25,000                                
                                         
 
 
(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 May 2007, the DTE Energy Board of Directors authorized the repurchase of up to $850 million of common stock through 2009. During 2009, no repurchases of common stock were made under this authorization that expired on December 31, 2009.


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COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN
 
Total Return To Shareholders
(Includes reinvestment of dividends)
 
                                         
    Annual Return Percentage
 
    Years Ending December  
Company/Index
  2005     2006     2007     2008     2009  
 
DTE Energy Company
    4.77       17.66       (5.03 )     (14.37 )     30.08  
S&P 500 Index
    4.91       15.79       5.49       (37.00 )     26.46  
S&P 500 Multi-Utilities Index
    17.04       16.74       10.86       (24.34 )     20.93  
 
                                                 
    Base
    Indexed Returns
 
    Period
    Years Ending December  
Company/Index
  2004     2005     2006     2007     2008     2009  
 
DTE Energy Company
    100       104.77       123.28       117.07       100.25       130.40  
S&P 500 Index
    100       104.91       121.48       128.16       80.74       102.11  
S&P 500 Multi-Utilities Index
    100       117.04       136.63       151.47       114.60       138.58  
 
(PERFORMANCE GRAPH)


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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.
 
                                         
    2009     2008     2007     2006     2005  
    (in Millions, except per share amounts)  
 
Operating Revenues
  $ 8,014     $ 9,329     $ 8,475     $ 8,157     $ 8,094  
                                         
Net Income Attributable to DTE Energy Company
                                       
Income from continuing operations(1)
  $ 532     $ 526     $ 787     $ 389     $ 272  
Discontinued operations
          20       184       43       268  
Cumulative effect of accounting changes
                      1       (3 )
                                         
Net Income Attributable to DTE Energy Company
  $ 532     $ 546     $ 971     $ 433     $ 537  
                                         
Diluted Earnings Per Common Share
                                       
Income from continuing operations
  $ 3.24     $ 3.22     $ 4.61     $ 2.18     $ 1.54  
Discontinued operations
          .12       1.08       .24       1.52  
Cumulative effect of accounting changes
                      .01       (.01 )
                                         
Diluted Earnings Per Common Share
  $ 3.24     $ 3.34     $ 5.69     $ 2.43     $ 3.05  
                                         
Financial Information
                                       
Dividends declared per share of common stock
  $ 2.12     $ 2.12     $ 2.12     $ 2.075     $ 2.06  
Total assets
  $ 24,195     $ 24,590     $ 23,742     $ 23,785     $ 23,335  
Long-term debt, including capital leases
  $ 7,370     $ 7,741     $ 6,971     $ 7,474     $ 7,080  
Shareholders’ equity
  $ 6,278     $ 5,995     $ 5,853     $ 5,849     $ 5,769  
 
 
(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 $80 million after-tax gain on the sale of a portion of the Barnett shale properties. See Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Report.


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
OVERVIEW
 
DTE Energy is a diversified energy company with 2009 operating revenues in excess of $8 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:
 
                         
    2009     2008     2007  
    (in Millions, except earnings per share)  
 
Income from continuing operations
  $ 535     $ 531     $ 791  
Diluted earnings per common share from continuing operations
  $ 3.24     $ 3.22     $ 4.61  
Net income attributable to DTE Energy Company
  $ 532     $ 546     $ 971  
Diluted earnings per common share
  $ 3.24     $ 3.34     $ 5.69  
 
The decrease in 2009 Net income attributable to DTE Energy from 2008 was primarily due to the $80 million after-tax gain recorded in the Unconventional Gas Production segment on the 2008 sale of a portion of Barnett shale properties, partially offset by higher earnings in the Electric Utility and Energy Trading segments. The decrease in Net income attributable to DTE Energy in 2008 from 2007 was primarily due to $370 million in net income resulting from the $580 million after-tax gain on the 2007 sale of the Antrim shale gas exploration and production business, partially offset by $210 million after-tax losses recognized on related hedges, including recognition of amounts previously recorded in accumulated other comprehensive income during 2007.
 
The items discussed below influenced our current financial performance and/or may affect future results:
 
  •  Impacts of national and regional economic conditions;
 
  •  Effects of weather on utility operations;
 
  •  Collectibility of accounts receivable on utility operations;
 
  •  Impact of regulatory decisions on utility operations;
 
  •  Non-utility operations;
 
  •  Capital investments, including required renewable, energy-efficiency, environmental, reliability-related and other costs; and
 
  •  Environmental matters.
 
Reference in this report to “we,” “us,” “our,” “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
 
UTILITY OPERATIONS
 
Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 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 customers throughout Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.


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Impact of National and Regional Economic Conditions
 
Revenues from our utility operations follow the economic cycles of the customers we serve. Unfavorable national and regional economic trends have resulted in reduced demand for electricity and natural gas in our service territory with corresponding declines in our revenues.
 
                         
    2009     2008     2007  
    (in Millions)  
 
Revenues
                       
Detroit Edison
  $ 4,714     $ 4,874     $ 4,900  
MichCon
    1,788       2,152       1,875  
 
During 2009, Detroit Edison experienced decreases in sales, predominantly in the industrial class, and to a lesser extent in the residential and commercial classes, partially offset by higher interconnection sales. MichCon’s revenues were lower due primarily to lower natural gas costs and customer conservation. We expect to minimize the impacts of declines in average customer usage through regulatory mechanisms which will decouple our revenue levels from sales volumes. We expect to be impacted by the challenges in the domestic automotive and steel industries and the timing and level of recovery in the national and regional economies. Direct and indirect effects of further automotive and other industrial plant closures could have a significant impact on the results of Detroit Edison. As discussed further below, deteriorating economic conditions impact our ability to collect amounts due from our electric and gas customers and drive increased thefts of electricity and natural gas. In the face of these economic conditions, we are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength.
 
Collectibility of Accounts Receivable on Utility Operations
 
Although lower than peak levels in 2008, both utilities continue to experience high levels of past due receivables primarily attributable to economic conditions. Our service territories continue to experience high levels of unemployment, underemployment and low income households, home foreclosures and a lack of adequate levels of assistance for low-income customers. Despite the current economic conditions, total arrears were reduced during 2009 in our electric and gas utilities. We have taken actions to manage the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers.
 
                         
    2009     2008     2007  
    (in Millions)  
 
Uncollectible Expense
                       
Detroit Edison
  $ 78     $ 87     $ 65  
MichCon
    93       126       70  
                         
    $ 171     $ 213     $ 135  
 
The MPSC has provided for an uncollectible expense tracking mechanism for MichCon since 2005. The uncollectible expense tracking mechanism enables MichCon to recover or refund 90 percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC.
 
The January 2010 MPSC electric rate order provided for an uncollectible expense tracking mechanism for Detroit Edison. The uncollectible expense tracking mechanism enables Detroit Edison to recover or refund 80 percent of the difference between the actual uncollectible expense for each year and $66 million after an annual reconciliation proceeding before the MPSC.
 
The bankruptcies of General Motors Corporation (GM) and Chrysler LLC (Chrysler) did not have a significant impact to our uncollectible expense in 2009.


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Impact of Regulatory Decisions on Utility Operations
 
On January 11, 2010, the MPSC issued an order in Detroit Edison’s January 26, 2009 rate case filing. The MPSC approved an annual revenue increase of $217 million or a 4.8% increase in Detroit Edison’s annual revenue requirement for 2010. Included in the approved increase in revenues was a return on equity of 11% on an expected 49% equity and 51% debt permanent capital structure. Since the final rate relief ordered was less than the Company’s self-implemented rate increase of $280 million effective on July 26, 2009, the MPSC ordered refunds for the period the self-implemented rates were in effect. Detroit Edison has recorded a refund liability of $27 million at December 31, 2009 representing the 2009 portion of the estimated refund due customers, including interest. The MPSC ordered Detroit Edison to file a refund plan by April 1, 2010.
 
Other key aspects of the MPSC order include the following:
 
  •  Continued progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;
 
  •  Continued application of an adjustment mechanism for Electric Choice sales that reconciles actual customer choice sales with a base customer choice sales level of 1,586 GWh;
 
  •  Continued application of adjustment mechanisms 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 $117 million and $47 million, respectively. The change in base expense level was applied retroactive to the July 26, 2009 self-implementation date;
 
  •  Implementation of a pilot Revenue Decoupling Mechanism, that will compare actual (non-weather normalized) sales per customer with the base sales per customer level established in this case for the period February 1, 2010 to January 31, 2011; and
 
  •  Implementation of an Uncollectible Expense Tracking Mechanism, based on a $66 million expense level, with an 80/20 percent sharing of the expenses above or below the base amount. The Uncollectible Expenses Tracking Mechanism was implemented retroactive to the July 26, 2009 self-implementation date.
 
MichCon filed a general rate case on June 9, 2009 based on a 2008 historical test year. The filing with the MPSC requested a $193 million, or 11.5 percent average increase in MichCon’s annual revenues for a 2010 projected test year. The requested $193 million increase in revenues is required to recover the increased costs associated with increased investments in net plant and working capital, an increase in the base level of the uncollectible expense tracking mechanism and the cost of natural gas theft primarily due to economic conditions in Michigan, sales reductions due to customer conservation and the trend of warmer weather on MichCon’s market, and increasing operating costs, largely due to inflation. Pursuant to the October 2008 Michigan legislation, and the settlement in MichCon’s last base gas sale case, MichCon self-implemented $170 million of its requested annual increase on January 1, 2010. This increase will remain in place until a final order is issued by the MPSC, which is expected in June 2010, subject to refund. See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
NON-UTILITY OPERATIONS
 
We have significant investments in non-utility 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. We expect growth opportunities in the Gas Storage and Pipelines and Power and Industrial Projects segments in the future. Expansion of these businesses will also result in our ability to further diversify geographically.
 
Gas Storage and Pipelines owns partnership interests in two natural gas storage fields and two interstate pipelines serving the Midwest, Ontario and Northeast markets. Much of the growth in demand for natural gas is expected to occur in the Mid-Atlantic and New England regions. Forecasts indicate that these regions will require incremental gas storage and pipeline infrastructure to meet demand growth. Our Vector and


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Millennium pipelines are well-positioned to provide access routes and low-cost expansion options to these markets.
 
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 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. Due to economic conditions and low natural gas prices during the year, we chose to do minimal lease acquisitions and reduce the number of new wells this year. However, we continue to evaluate leasing opportunities in active development areas in the Barnett shale to optimize our existing portfolio.
 
Power and Industrial Projects is comprised primarily of projects that deliver energy and 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 services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. Renewable energy, environmental and economic trends are creating growth opportunities. The increasing number of states with renewable portfolio standards and energy efficiency mandates provides the opportunity to market the expertise of the Power and Industrial Projects segment in landfill gas, on-site energy management, waste-wood power generation, and other related services.
 
Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities which may include the management of associated storage and transportation contracts on the customers’ behalf.
 
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.
 
CAPITAL INVESTMENTS
 
We anticipate significant capital investments during the next three years concentrated primarily in Detroit Edison.
 
         
    2010-2012  
    (in Billions)  
 
Capital Investments
       
Detroit Edison
  $ 3.0 — 3.4  
MichCon
    0.4 — 0.5  
Non-Utility
    0.6 — 0.9  
         
    $ 4.0 — 4.8  
 
Our utility businesses require significant capital investments each year in order to maintain and improve the reliability of their asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. In addition, Detroit Edison’s investments (excluding investments in new base-load generation capacity, if any) will be driven by renewable investment and environmental controls expenditures. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Non-utility investments are expected primarily in continued investment in gas storage and pipeline assets and renewable opportunities in the Power and Industrial Projects businesses.


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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.
 
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. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. It is not possible to quantify the impact of those expected rulemakings at this time.
 
In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and Title V operating permit requirements under the Clean Air Act. We believe that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. We could also be required to install additional pollution control equipment at some or all of the power plants in question, engage in Supplemental Environmental Programs, and/or pay fines. We cannot predict the financial impact or outcome of this matter, or the timing of its resolution.
 
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, some of which have already been completed, but more are expected 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 and in April 2009 upheld EPA’s use of this provision in determining best available technology for reducing environmental impacts. Concurrently, the EPA continues to develop a revised rule, a draft of which is expected to be published by summer 2010. The EPA has also proposed an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.
 
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. Detroit Edison owns, or previously owned, three former MGP sites. In addition to the MGP sites, we are also in the process of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash storage facility, electrical distribution substations, gas pipelines, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years.
 
Landfill— Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction. The results of the engineering study show that the estimated cost to perform the embankment repairs are $17 million which we expect to incur over the next four years.
 
The EPA has expressed its intentions to develop new federal regulations for coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). A proposed regulation is expected in the first


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quarter of 2010. Among the options EPA is currently considering, is a ruling that may designate coal ash as a “Hazardous Waste” as defined by RCRA. However, agencies and legislatures have urged EPA to regulate coal ash as a non-hazardous waste. If EPA were to designate coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes. Some of the regulatory actions currently being contemplated could have a material adverse impact on our operations and financial position and the rates we charge our customers.
 
Global Climate Change
 
Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs to emit greenhouse gases. Despite action by the Senate Environmental and Public Works Committee to pass a similar but more stringent bill in October 2009, full Senate action on a climate bill is not expected before the spring of 2010. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. Pending or future legislation or other regulatory actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures and the purchase of emission allowances from market sources. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify these impacts on DTE Energy or its customers at this time.
 
See Notes 12 and 20 of the Notes to Consolidated Financial Statements in Item 8 of this Report and Items 1 and 2 Business and Properties.
 
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.
 
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.


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RESULTS OF OPERATIONS
 
The following sections provide a detailed discussion of the operating performance and future outlook of our segments.
 
                         
    2009     2008     2007  
    (in Millions)  
 
Net Income Attributable to DTE Energy by Segment:
                       
Electric Utility
  $ 376     $ 331     $ 317  
Gas Utility
    80       85       70  
Gas Storage and Pipelines
    49       38       34  
Unconventional Gas Production(1)
    (9 )     84       (217 )
Power and Industrial Projects
    31       40       49  
Energy Trading
    75       42       32  
Corporate & Other(1)
    (70 )     (94 )     502  
Income (Loss) from Continuing Operations:
                       
Utility
    456       416       387  
Non-utility
    146       204       (102 )
Corporate & Other
    (70 )     (94 )     502  
                         
      532       526       787  
Discontinued Operations
          20       184  
                         
Net Income Attributable to DTE Energy Company
  $ 532     $ 546     $ 971  
                         
 
 
(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 10 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
 
ELECTRIC UTILITY
 
Our Electric Utility segment consists of Detroit Edison.
 
Electric Utility results are discussed below:
 
                         
    2009     2008     2007  
    (in Millions)  
 
Operating Revenues
  $ 4,714     $ 4,874     $ 4,900  
Fuel and Purchased Power
    1,491       1,778       1,686  
                         
Gross Margin
    3,223       3,096       3,214  
Operation and Maintenance
    1,277       1,322       1,422  
Depreciation and Amortization
    844       743       764  
Taxes Other Than Income
    205       232       277  
Asset (Gains) Losses, Reserves and Impairments, Net
    (2 )     (1 )     8  
                         
Operating Income
    899       800       743  
Other (Income) and Deductions
    295       283       277  
Income Tax Provision
    228       186       149  
                         
Net Income Attributable to DTE Energy Company
  $ 376     $ 331     $ 317  
                         
Operating Income as a Percent of Operating Revenues
    19 %     16 %     15 %


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Gross margin increased $127 million during 2009 and decreased $118 million in 2008. The following table displays changes in various gross margin components relative to the comparable prior period:
 
                 
    2009     2008  
    (in Millions)  
 
December 2008 rate order
  $ 80     $  
Securitization bond and tax surcharge rate increase
    62        
July 2009 rate self-implementation, net of refund
    93        
Energy Optimization and Renewable Energy surcharge
    54        
April 2008 expiration of show cause rate decrease
    25       46  
Weather
    (66 )     (37 )
Reduction in customer demand and other
    (121 )     (127 )
                 
Increase (decrease) in gross margin
  $ 127     $ (118 )
                 
 
                         
    2009     2008     2007  
    (in Thousands of MWh)  
 
Electric Sales
                       
Residential
    14,625       15,492       16,147  
Commercial
    18,200       18,920       19,332  
Industrial
    9,922       13,086       13,338  
Other
    3,229       3,218       3,300  
                         
      45,976       50,716       52,117  
Interconnection sales(1)
    5,156       3,583       3,587  
                         
Total Electric Sales
    51,132       54,299       55,704  
                         
Electric Deliveries
                       
Retail and Wholesale
    45,976       50,716       52,117  
Electric Customer Choice, including self generators(2)
    1,477       1,457       2,239  
                         
Total Electric Sales and Deliveries
    47,453       52,173       54,356  
                         
 
 
(1) Represents power that is not distributed by Detroit Edison.
 
(2) Includes deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.
 


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Power Generated and Purchased
  2009     2008     2007  
    (in Thousands of MWh)  
 
Power Plant Generation
                                               
Fossil
    40,595       74 %     41,254       71 %     42,359       72 %
Nuclear
    7,406       14       9,613       17       8,314       14  
                                                 
      48,001       88       50,867       88       50,673       86  
Purchased Power
    6,495       12       6,877       12       8,422       14  
                                                 
System Output
    54,496       100 %     57,744       100 %     59,095       100 %
Less Line Loss and Internal Use
    (3,364 )             (3,445 )             (3,391 )        
                                                 
Net System Output
    51,132               54,299               55,704          
                                                 
Average Unit Cost ($/MWh)
                                               
Generation(1)
  $ 18.20             $ 17.93             $ 15.83          
                                                 
Purchased Power
  $ 37.74             $ 69.50             $ 62.40          
                                                 
Overall Average Unit Cost
  $ 20.53             $ 24.07             $ 22.47          
                                                 
 
 
(1) Represents fuel costs associated with power plants.
 
Operation and maintenance expense decreased $45 million in 2009 and decreased $100 million in 2008. The decrease in 2009 was primarily due to $71 million from continuous improvement initiatives and other cost reductions resulting in lower contract labor and outside services expense, information technology and other staff expenses, $14 million of lower employee benefit-related expenses, lower storm expenses of $12 million, $9 million of reduced uncollectible expenses and $6 million of reduced maintenance activities, partially offset by higher pension and health care costs of $54 million and $14 million of energy optimization and renewable energy expenses. The decrease in 2008 was due primarily to lower information systems implementation costs of $60 million, lower employee benefit-related expenses of $45 million and $29 million from continuous improvement initiatives resulting in lower contract labor and outside services expense, information technology and other staff expenses, partially offset by higher uncollectible expenses of $22 million.
 
Depreciation and amortization expense increased $101 million in 2009 due primarily to a higher depreciable base and increased amortization of regulatory assets and decreased $21 million in 2008 due primarily to decreased amortization of regulatory assets.
 
Taxes other than income were lower by $27 million due primarily to a $30 million reduction in property tax expense due to refunds received in settlement of appeals of assessments for prior years. Taxes 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.
 
Outlook — Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and continued high levels 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 January 2010 MPSC rate order, provided for an uncollectible expense tracking mechanism and a revenue decoupling mechanism will assist in mitigating these impacts.
 
To address the challenges of the national and regional economies, we continue to move forward in our efforts to improve the operating performance and cash flow of Detroit Edison. We continue to favorably resolve outstanding regulatory issues, many of which were addressed by Michigan legislation. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, we face additional issues, such as higher levels of capital spending, volatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue

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an intense focus on our continuous improvement efforts to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
 
GAS UTILITY
 
Our Gas Utility segment consists of MichCon and Citizens.
 
Gas Utility results are discussed below:
 
                         
    2009     2008     2007  
    (in Millions)  
 
Operating Revenues
  $ 1,788     $ 2,152     $ 1,875  
Cost of Gas
    1,057       1,378       1,164  
                         
Gross Margin
    731       774       711  
Operation and Maintenance
    415       464       429  
Depreciation and Amortization
    107       102       93  
Taxes Other Than Income
    49       48       56  
Asset (Gains) and Losses, Net
    (18 )     (26 )     (3 )
                         
Operating Income
    178       186       136  
Other (Income) and Deductions
    59       60       43  
Income Tax Provision
    39       41       23  
                         
Net Income Attributable to DTE Energy Company
  $ 80     $ 85     $ 70  
                         
Operating Income as a Percent of Operating Revenues
    10 %     9 %     7 %
 
Gross margin decreased $43 million in 2009 and increased $63 million in 2008. The decrease in 2009 reflects $28 million of lower revenues from the uncollectible tracking mechanism, $15 million of additional lost and stolen gas, $12 million of continued customer conservation efforts, $5 million of lower end user transportation revenue, $5 million of realized hedging losses, the effects of unfavorable weather of $4 million and reduced late payment revenue of $4 million, partially offset by $22 million higher midstream transportation and storage revenues, $5 million in energy optimization revenues and $5 million higher appliance service revenues. 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.
 
                         
    2009     2008     2007  
    (in Millions)  
 
Gas Markets
                       
Gas sales
  $ 1,443     $ 1,824     $ 1,536  
End user transportation
    144       143       140  
Intermediate transportation
    69       73       70  
Storage and other
    132       112       129  
                         
    $ 1,788     $ 2,152     $ 1,875  
                         
Gas Markets (in Bcf)
                       
Gas sales
    137       148       148  
End user transportation
    124       123       132  
                         
      261       271       280  
Intermediate transportation
    463       438       399  
                         
      724       709       679  
                         


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Operation and maintenance expense decreased $49 million in 2009 and increased $35 million in 2008. The decrease in 2009 was primarily due to $33 million of reduced uncollectible expenses, $15 million of lower employee benefit-related expenses, $14 million from continuous improvement initiatives and other cost reductions resulting in lower contract labor and outside services expense, information technology and other staff expenses, partially offset by higher health care expenses of $8 million and $4 million of energy optimization expenses. The 2008 increase is primarily attributable to $56 million of higher uncollectible expenses, partially offset by $14 million from continuous improvement initiatives resulting in lower contract labor and outside services expense, information technology and other staff expenses and $14 million of reduced pension and health care expenses. Uncollectible expense was higher in 2008 due to an analysis of our greater than ninety day receivables that indicated a change in the mix of customers in that group and therefore an increased risk of collection. The changes in uncollectible expenses are substantially offset by changes in revenues from the uncollectible tracking mechanism included in the gross margin discussion.
 
Asset (gains) losses, net decreased $8 million due to a lower gain on the sale of base gas of $15 million and a gain related to the sale of certain gathering and processing assets. The 2008 increase of $23 million was due primarily to the sale of base gas.
 
Outlook — Unfavorable national and regional economic trends have resulted in a decrease in the number of customers in our service territory, customer conservation and continued high levels of theft and 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 uncollectible tracking mechanism provided by the MPSC assists in mitigating the continued pressure on accounts receivable.
 
To address the challenges of the national and regional economies, we continue to move forward in our efforts to improve the operating performance and cash flow of Gas Utility. We continue to resolve outstanding regulatory issues. Looking forward, we face additional issues, such as volatility in gas prices, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue an intense focus on our continuous improvement efforts to improve productivity, minimize lost and stolen gas, remove waste and decrease our costs while improving customer satisfaction.
 
GAS STORAGE AND PIPELINES
 
Our Gas Storage and Pipelines segment consists of our non-utility gas pipelines and storage businesses.
 
Gas Storage and Pipelines results are discussed below:
 
                         
    2009     2008     2007  
    (in Millions)  
 
Operating Revenues
  $ 82     $ 71     $ 66  
Operation and Maintenance
    15       12       13  
Depreciation and Amortization
    5       5       6  
Taxes Other Than Income
    2       3       3  
Asset (Gains) and Losses, Net
          1       (1 )
                         
Operating Income
    60       50       45  
Other (Income) and Deductions
    (23 )     (12 )     (7 )
Income Tax Provision
    33       24       18  
                         
Net Income
    50       38       34  
Noncontrolling interest
    1              
                         
Net Income Attributable to DTE Energy
  $ 49     $ 38     $ 34  
                         
 
Net income attributable to DTE Energy increased $11 million and $4 million in 2009 and 2008, respectively. The 2009 increase was driven by higher operating revenues resulting from increased capacity sold and higher rates from renewing storage contracts related to long-term agreements. In addition, there were


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higher equity earnings from our investments in the Vector and Millennium Pipelines, reflecting a first full year of operations for Millennium. The 2008 increase is due to higher storage revenues related to expansion of capacity and higher other income primarily driven by higher equity earnings in the Vector and Millennium Pipelines, partially offset by a higher tax provision due to the MBT in 2008.
 
Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan. In 2009, an additional 3 Bcf of storage capacity was placed in service. The Vector Pipeline Phase 2 expansion which added approximately 100 MMcf/day, was placed in service in October 2009 and is supported by customers under long-term contracts. Millennium Pipeline was placed in-service in December 2008 and currently has nearly 85 percent of its capacity sold to customers under long-term contracts. We are also a 50 percent owner in the proposed Dawn Gateway Pipeline. The Dawn Gateway Project is designed to initially transport 360,000 dth/d from our Michigan storage facilities to the Dawn Hub in Ontario, Canada, and upon successful and timely regulatory approval, is expected to be in service in the fourth quarter 2010.
 
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. 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 ($80 million after-tax) on the sale in 2008.
 
Unconventional Gas Production results are discussed below:
 
                         
    2009     2008     2007  
    (in Millions)  
 
Operating Revenues
  $ 31     $ 48     $ (228 )
Operation and Maintenance
    15       22       36  
Depreciation, Depletion and Amortization
    16       12       22  
Taxes Other Than Income
    1       1       8  
Asset (Gains) and Losses, Net
    6       (120 )     27  
                         
Operating Income (Loss)
    (7 )     133       (321 )
Other (Income) and Deductions
    6       2       13  
Income Tax Provision (Benefit)
    (4 )     47       (117 )
                         
Net Income (Loss) Attributable to DTE Energy Company
  $ (9 )   $ 84     $ (217 )
                         
 
Operating revenues decreased $17 million in 2009 and increased $276 million in 2008. The 2009 decrease is the result of lower commodity prices, while production remained relatively flat. The 2008 increase was principally due to the impact of losses on 2007 financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales through 2013. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $47 million in 2008. The decreases were principally due to lower natural gas sales volumes as a result of our monetization initiatives, partially offset by higher commodity prices and higher gas and oil production on retained wells.
 
Operation and maintenance expense decreased $7 million in 2009 due to operational efficiencies and lower costs for goods and services. The 2008 decrease is primarily attributable to the sale of a portion of the Barnett shale in January 2008 and the Antrim sale in June 2007.
 
Asset (gains) and losses, net decreased $126 in 2009 and increased $147 million in 2008. The 2009 decrease as compared to 2008 was due to the gain of $128 million ($80 million after-tax) on the 2008 sale of a portion of our Barnett shale properties and $2 million lower impairment in 2009 of expired or expiring leasehold positions that the company does not intend to drill at current commodity prices. The increase in 2008 of $147 million was due to the gain on sale of Barnett shale core properties, partially offset by $8 million


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of impairment losses primarily related to leases on unproved acreage that we did not anticipate developing due to economic conditions.
 
Outlook — In the longer-term, 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 asset base, when conditions are appropriate. Our strategy for 2010 is to maintain our focus on reducing operating expenses and optimizing production volume. During 2010, we expect to invest approximately $25 million to drill 10 to 15 new wells and achieve production of approximately 5 Bcfe of natural gas, compared with 5 Bcfe in 2009.
 
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.
 
Power and Industrial Projects results are discussed below:
 
                         
    2009     2008     2007  
    (in Millions)  
 
Operating Revenues
  $ 661     $ 987     $ 1,244  
Operation and Maintenance
    593       899       1,143  
Depreciation and Amortization
    40       34       41  
Taxes other than Income
    9       12       13  
Other Asset (Gains) and Losses, Reserves and Impairments, Net
    (6 )     6        
                         
Operating Income
    25       36       47  
Other (Income) and Deductions
    (1 )     (20 )     (11 )
Income Taxes
                       
Provision
    5       18       18  
Production Tax Credits
    (12 )     (7 )     (11 )
                         
      (7 )     11       7  
                         
Net Income
    33       45       51  
Noncontrolling interest
    2       5       2  
                         
Net Income Attributable to DTE Energy Company
  $ 31     $ 40     $ 49  
                         
 
Operating revenues decreased $326 million in 2009 and $257 million in 2008. The 2009 decrease is due primarily to $111 million reduction in certain coal structured transactions, $176 million of lower pricing and volumes of coal and emissions and $84 million of lower coke demand, partially offset by a $107 million increase in coal related services. The 2008 decrease 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.
 
Operation and maintenance expense decreased $306 million in 2009 and $244 million in 2008. The 2009 decrease is due primarily to $111 million decrease in certain coal structured transactions and $64 million of lower coke demand, $141 million of lower pricing and volumes of coal and emissions and operating expenses, partially offset by $75 million of higher coal related services. The 2008 decrease mostly reflects $174 million of lower coal transportation costs driven by reduced sales combined with a reduction in coal trading results.
 
Depreciation and amortization expense increased $6 million in 2009 and decreased $7 million in 2008. In 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second quarter of 2008, our work on this planned monetization was discontinued and the assets and liabilities of the Projects


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were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used.
 
Other assets (gains) losses, reserves and impairments, net increased $12 million in 2009 and expense decreased $6 million in 2008. This variation in this item is due primarily to a loss recorded in 2008 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 offset by gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production. Production at this coke battery was operating at lower production volumes in 2009.
 
Other (income) and deductions were lower by $19 million in 2009 due primarily to higher inter-company interest associated with project construction and a reduction in equity earnings in an investment in a coke battery.
 
Outlook — The stabilization in the U.S. economy is having a positive impact on our customers in the steel industry and we expect a corresponding improvement in demand for metallurgical coke and pulverized coal supplied to these customers for 2010. We supply onsite energy services to the domestic automotive manufacturers who have also experienced stabilized demand for autos. Chrysler and GM have emerged from Chapter 11 bankruptcy protection. We have been in discussions with both automakers and do not anticipate significant impacts to onsite energy services. Our onsite energy services will continue to be delivered in accordance with the terms of long-term contracts. We continue to monitor developments in this sector.
 
In 2010, we will continue to capture benefits from production tax credits generated from our steel industry fuel and our reduced emission fuel projects. We will also begin to generate production tax credits from our reduced emission fuel projects. In 2011, our existing long-term rail transportation contract, which is at rates significantly below the current market, will expire and we anticipate a decrease in transportation-related revenue of approximately $120 million as a result. 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 energy projects to serve energy intensive industrial customers. We will also continue to look for opportunities to acquire energy projects and biomass fired generating projects for favorable prices.
 
ENERGY TRADING
 
Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities which may include the management of associated storage and transportation contracts on the customers’ behalf.


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Energy Trading results are discussed below:
 
                         
    2009     2008     2007  
    (in Millions)  
 
Operating Revenues
  $ 804     $ 1,388     $ 924  
Fuel, Purchased Power and Gas
    603       1,235       806  
                         
Gross Margin
    201       153       118  
Operation and Maintenance
    71       68       58  
Depreciation and Amortization
    5       5       5  
Taxes Other Than Income
    3       2       1  
                         
Operating Income
    122       78       54  
Other (Income) and Deductions
    10       5       5  
Income Tax Provision (Benefit)
    37       31       17  
                         
Net Income Attributable to DTE Energy Company
  $ 75     $ 42     $ 32  
                         
 
Gross margin increased $48 million in 2009 and $35 million in 2008. Overall, Operating Revenues and Fuel, Purchased Power and Gas were impacted by a decrease in gas and power commodity prices in 2009 as compared to 2008. The $48 million increase in gross margin in 2009 was due to increases in realized margins of $69 million, offset by decreases in unrealized margins of $21 million. The $69 million increase in realized margins was primarily the result of increases in our gas trading strategy and timing-related increases in our gas storage and transportation optimization strategies. The $21 million decrease in unrealized margins consisted of unfavorable results of $58 million from our gas trading and gas marketing and origination strategies, partially offset by increases of $29 million in our power trading and timing-related improvements of $8 million in our oil strategies.
 
The 2008 increase was due to higher unrealized margin of $66 million offset by a decrease in realized margin of $31 million. The increase in unrealized margins includes gains in our gas strategies and the absence of $30 million in mark-to-market losses in June 2007 reflecting revisions of valuation estimates for natural gas contracts. The decrease in realized margin was due to unfavorable results 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.
 
Operation and maintenance expense increased $3 million and $10 million in 2009 and 2008, respectively. The 2009 increase was due to higher payroll and incentive costs and commissions, partially offset by lower contractor expense and allocated corporate costs. The 2008 increase is due to higher payroll and incentive costs and allocated corporate costs.
 
Income tax provision increased $6 million in 2009 due to an increase in income taxes resulting from higher pretax income, partially offset by $10 million of favorable tax-related adjustments primarily resulting from the settlement of federal income tax audits.
 
Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments, physical commodity contracts and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power transmission and generation capacity positions. Energy Trading also provides power and ancillary services and natural gas to various utilities which may include the management of associated storage and transport contracts on the customers’ behalf. Most financial instruments and physical power and gas contracts 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. Our strategy is to economically manage the price risk of these underlying non-derivative contracts and assets with futures, forwards, swaps and options. This results in gains and losses that are recognized in different interim and annual accounting periods.


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See also the “Fair Value” section that follows.
 
CORPORATE & OTHER
 
Corporate & Other includes various holding company activities and holds certain non-utility debt and energy-related investments.
 
Factors impacting income:  The 2009 net loss of $70 million decreased from the net loss of $94 million in 2008 due to $34 million favorable tax-related adjustments primarily resulting from the settlement of federal income tax audits, $10 million lower inter-company interest expense and $9 million lower costs related to natural gas forward contracts associated with the 2007 sale of the Antrim Shale properties. These favorable variances were partially offset by a $10 million donation of cash and available-for-sale securities to the DTE Energy Foundation, $10 million resulting from a realignment of employee benefit expense from MichCon, $7 million increase in financing fees, $1 million increased impairment of investments and a $1 million decrease in interest income. The 2008 net loss of $94 million was lower than the 2007 net income of $502 million due to the 2007 gain on the sale of the Antrim shale gas exploration and production business for approximately $900 million ($580 million after-tax).
 
DISCONTINUED OPERATIONS
 
Synthetic Fuel
 
Due to the expiration of synfuel production tax credits in 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation as of December 31, 2007.
 
See Note 10 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
 
Effective January 1, 2008, we adopted ASC 820 (SFAS No. 157, Fair Value Measurements). The cumulative effect adjustment upon adoption of ASC 820 represented a $4 million increase to the January 1, 2008 balance of retained earnings. See also the “Fair Value” section.
 
Effective January 1, 2007, we adopted ASC 740 (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 ASC 740 represented a $5 million reduction to the January 1, 2007 balance of retained earnings.
 
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. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2010, we expect that cash from operations will be lower due to higher tax payments and working capital requirements. We anticipate base level capital investments and expenditures for existing businesses in 2010 of up to $1.4 billion. The capital needs of our utilities will increase due primarily to renewable and energy optimization related expenditures. We incurred environmental expenditures of approximately $116 million in 2009 and we expect over $2.2 billion of future capital expenditures through 2019 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. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.
 
Debt maturing in 2010 totals approximately $661 million.
 


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    2009     2008     2007  
    (in Millions)  
 
Cash and Cash Equivalents
                       
Cash Flow From (Used For)
                       
Operating activities:
                       
Net income
  $ 535     $ 553     $ 787  
Depreciation, depletion and amortization
    1,020       899       926  
Deferred income taxes
    205       348       144  
Gain on sale of non-utility business
          (128 )     (900 )
Gain on sale of synfuel and other assets, net and synfuel impairment
    (10 )     (35 )     (253 )
Working capital and other
    69       (78 )     421  
                         
      1,819       1,559       1,125  
                         
Investing activities:
                       
Plant and equipment expenditures — utility
    (960 )     (1,183 )     (1,035 )
Plant and equipment expenditures — non-utility
    (75 )     (190 )     (264 )
Proceeds from sale of non-utility business
          253       1,262  
Proceeds (refunds) from sale of synfuels and other assets
    83       (278 )     417  
Restricted cash and other investments
    (112 )     (125 )     (50 )
                         
      (1,064 )     (1,523 )     330  
                         
Financing activities:
                       
Issuance of long-term debt
    427       1,310       50  
Redemption of long-term debt
    (486 )     (446 )     (393 )
Repurchase of long-term debt
          (238 )      
Short-term borrowings, net
    (417 )     (340 )     (47 )
Issuance of common stock
    35              
Repurchase of common stock
          (16 )     (708 )
Dividends on common stock and other
    (348 )     (354 )     (370 )
                         
      (789 )     (84 )     (1,468 )
                         
Net Decrease in Cash and Cash Equivalents
  $ (34 )   $ (48 )   $ (13 )
                         
 
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 $1.8 billion in 2009, increased $260 million from the comparable 2008 period. The operating cash flow comparison primarily reflects lower working capital requirements and higher net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred taxes and gains on sales of assets).
 
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 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 $1.1 billion in 2009, compared with net cash used for investing activities of $1.5 billion in 2008. The change was primarily driven by reduced capital expenditures by our utility and non-utility businesses and the completion of refund payments to our synfuel partners in 2008.
 
Net cash used for investing activities increased $1.9 billion in 2008, due primarily to the sale of our Antrim shale gas exploration and production business in 2007 which offset most of the capital expenditures during that period, and the completion of synfuel partner refunds in 2008.
 
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. The extension of the average maturity was accomplished at interest rates that lowered our debt costs.
 
Net cash used for financing activities was $789 million in 2009, compared to net cash used for financing activities of approximately $84 million for the same period in 2008. The change was primarily attributable to lower proceeds from the issuance of long-term debt.
 
Net cash used for financing activities decreased $1.4 billion in 2008 primarily related to the repurchase of common stock in 2007 and increased issuances of long-term debt.
 
Outlook
 
We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and the non-utility businesses. We expect growth in our utilities to be driven primarily by new and existing state and federal regulations that will result in additional environmental and renewable energy investments which will increase the base from which rates are determined. Our non-utility growth is expected from additional investments in energy projects as economic conditions improve.
 
We have been impacted by unfavorable national and regional economic trends that have reduced demand for electricity in our service territory. 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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In April 2009, we completed an early renewal of $975 million of our syndicated revolving credit facilities before their scheduled expiration in October 2009. The new $1 billion two-year facility will expire in 2011 and has similar covenants to the prior facility. A new two-year $50 million credit facility was completed in May 2009 and a new one-year $70 million credit facility was completed in June 2009. We have a $925 million five-year facility that expires in October 2010. We expect to pursue the renewal of that facility before its expiration. Given current conditions in the credit markets, we anticipate that the new facility will be similar to our April 2009 facility with respect to such items as bank participation, allocation levels and covenants. We are evaluating the need to renew our $70 million bi-lateral credit facility expiring in June 2010 which is used to support the issuance of letters of credit. See Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Report.
 
As a result of losses experienced in the 2008 financial markets, our benefit plan assets experienced negative returns, which have resulted in higher benefit costs and contributions in 2009 and potentially in future years relative to the recent past. During 2009, our pension plan and other postretirement benefit plans assets experienced positive returns of approximately 20% and 22%, respectively. During 2010, we expect to contribute up to $200 million to our pension plans and up to $130 million to our postretirement medical and life insurance benefit plans.
 
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 12, 13, and 14 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Contractual Obligations
 
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2009:
 
                                         
                            2015
 
Contractual Obligations
  Total     2010     2011-2012     2013-2014     and Beyond  
    (in Millions)  
 
Long-term debt:
                                       
Mortgage bonds, notes and other
  $ 6,768     $ 522     $ 1,118     $ 1,113     $ 4,015  
Securitization bonds
    933       140       314       374       105  
Trust preferred-linked securities
    289                         289  
Capital lease obligations
    76       14       21       18       23  
Interest
    5,763       492       822       687       3,762  
Operating leases
    208       33       54       38       83  
Electric, gas, fuel, transportation and storage purchase obligations(1)
    4,649       2,513       1,307       158       671  
Other long-term obligations(2)(3)(4)
    298       32       97       33       136  
                                         
Total obligations
  $ 18,984     $ 3,746     $ 3,733     $ 2,421     $ 9,084  
                                         
 
 
(1) Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.
 
(2) Includes liabilities for unrecognized tax benefits of $81 million.
 
(3) Excludes other long-term liabilities of $181 million not directly derived from contracts or other agreements.
 
(4) At December 31, 2009, 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


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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 21 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
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 DTE Energy 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. A downgrade below investment grade could potentially increase the borrowing costs of DTE Energy and its subsidiaries and may limit access to the capital markets. The impact of a downgrade will not affect our ability to comply with our existing debt covenants. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews.
 
In May 2009, Standard & Poor’s Rating Group (Standard & Poor’s) revised the outlook on DTE Energy and its subsidiaries to negative from stable, and lowered the short-term corporate credit and commercial paper ratings for DTE Energy, Detroit Edison and MichCon to A-3 from A-2. The revision was primarily due to concerns over Michigan’s economic climate. Moody’s Investors Service (Moody’s) affirmed our existing short-term ratings of P-2. In August 2009, Moody’s upgraded the majority of senior secured debt ratings of investment-grade regulated utilities by one notch as a result of revised notching guidelines between senior secured debt ratings and senior unsecured debt ratings. Both Detroit Edison’s and MichCon’s senior debt ratings were upgraded to A2 from A3. In January 2010, Standard & Poor’s raised its outlook on DTE Energy back to stable and raised the short-term credit ratings for DTE Energy, Detroit Edison and MichCon back to A-2 from A-3. We have experienced an improvement in our ability to issue commercial paper since the restoration of our short-term ratings. 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. Potential instability in the credit markets and any lowering of ratings may impact future access to the commercial paper markets, which may require us to draw on our back-up facilities.


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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−   A2   A−
    Commercial Paper   A-2   P-2   F2
MichCon
  Senior Secured Debt   BBB+   A2   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. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. Detroit Edison and MichCon are required to record 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 the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.
 
See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
Derivatives and Hedging Activities
 
Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities in the Consolidated Statements of Financial Position. 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. 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. Substantially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.
 
Fair value is defined as 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 in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which


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refer broadly to assumptions that market participants use in pricing assets and liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The fair value of derivative contracts is 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.
 
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 Item 7A. Quantitative and Qualitative Disclosures About Market Risk. See also the Fair Value section, herein. See Notes 4 and 5 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 on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. The allowance for doubtful accounts for our two utilities is calculated using the aging approach that utilizes rates developed in reserve studies and applies these factors to past due receivable balances. As a result of the reduction in past due receivables in 2009, our allowance for doubtful accounts decreased in 2009 compared to an increase in 2008. 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 expense tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. The MPSC provided for a similar tracking mechanism for Detroit Edison in its rate order received January 2010. 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 reporting units have goodwill or allocated goodwill resulting from purchase business combinations. We perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.
 
For Step 1 of the test, 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. We also employ market-based valuation techniques to test the reasonableness of the indications of value for the reporting units determined under the cash flow technique.
 
We performed our annual impairment test as of October 1, 2009 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. We also compared the


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aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to factors such as (1) an acquisition control premium (the price in excess of a stock’s market price that investors typically pay to gain control of an entity), and (2) the market’s apparent discounting of DTE Energy’s stock price due to ongoing uncertainty regarding the existing regulatory and automotive industry environment and DTE Energy’s diverse non-utility business portfolio. The results of the test and key estimates that were incorporated are as follows.
 
As of October 1, 2009 Valuation Date
 
                                     
          Fair Value
    Discount
    Terminal
     
Reporting Unit
  Goodwill     Reduction %(a)     Rate     Multiple(b)     Valuation Methodology(c)
    ($ in Millions)                        
 
Electric Utility
  $ 1,206       16 %     7 %     7.5 x   DCF, assuming stock sale
Gas Utility
    772       8 %     7 %     9.0 x   DCF, assuming stock sale
Energy Services
    28       64 %     13 %     8.5 x   DCF, assuming asset sale
Coal Services
    4       10 %     10 %     7.5 x   DCF, assuming asset sale
Gas Storage and Pipelines
    8       68 %     9 %     8.0 x   DCF, assuming asset sale
Energy Trading
    17       78 %     15 %     n/a     Blended DCF, economic value of trading portfolio
Unconventional Gas Production
    2       56 %     13 %     n/a     Blended DCF, transaction multiples
                                     
    $ 2,037                              
                                     
 
 
(a) Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value, including goodwill.
 
(b) Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA)
 
(c) Discounted cash flows (DCF) incorporated 2010-2014 projected cash flows plus a calculated terminal value.
 
The Gas Utility reporting unit passed Step 1 of the impairment test by a narrow margin. The narrow excess of fair value over carrying value is largely due to relatively low market values and market multiples of comparable entities referenced in our valuation. Further declines in market multiples, negative regulatory actions or other disruptions in cash flows for the Gas Utility reporting unit could result in an impairment charge in the foreseeable future. For example, at the current discount rate and holding all other variables constant, a 0.5x decrease in the terminal multiple would lower the fair value by approximately $130 million. At the lower fair value, the Gas Utility reporting unit would likely fail Step 1 of the test potentially resulting in a charge for impairment of goodwill following completion of the Step 2 analysis.
 
We perform an annual impairment test each October. In between annual tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. 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.
 
We monitor DTE Energy’s stock price in relation to its book value per share. DTE’s stock price declined significantly during the first quarter of 2009 and then increased and continued to recover throughout the rest of 2009. Refer to Note 6 of the Notes to Consolidated Financial Statements in Item 8 of this Report, for a discussion of factors that we considered when assessing triggering events in 2009.


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Due to the duration and severity of the decline in DTE Energy’s stock price in the first quarter, we performed an interim impairment test for all reporting units with allocated goodwill as of February 28, 2009. For the first quarter interim test, we updated projected future results, cash flows and discount rates to reflect existing regulatory actions and negative impacts from the deterioration in the regional and national economy. Terminal values that utilize an earnings multiple approach were updated to incorporate the current market values of comparable entities. As compared to the annual test performed in the fourth quarter of 2008, the valuations were negatively impacted by existing market factors with particular downward pressure on market multiples. All reporting units passed Step 1 of the impairment test.
 
We identified a trigger for our Energy Services reporting unit related to long-lived asset impairment tests that were performed during the second quarter on certain automotive-related project companies. The fair value of the reporting unit exceeded its carrying value including goodwill, therefore, the reporting unit passed Step 1 of the impairment test. As compared to the first quarter interim test, the second quarter valuation was favorably impacted by increased market multiples and an improved discount rate.
 
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 10 of Notes to Consolidated Financial Statements in Item 8 of this Report.
 
The Company’s Power and Industrial Projects segment has long-term contracts with GM to provide onsite energy services at certain of its manufacturing and administrative facilities. The long-term contracts provide for full recovery of its investment in the event of early termination. At December 31, 2009, the book value of long-lived assets used in the servicing of these facilities was approximately $65 million. Certain of these long-lived assets have been funded by non-recourse financing totaling approximately $56 million at December 31, 2009. The Company’s Power and Industrial Projects segment also has an equity investment of approximately $51 million in an entity which provides onsite services to Chrysler manufacturing facilities. Chrysler’s performance under the long-term contracts for services is guaranteed by Daimler North America Corporation (Daimler), a subsidiary of Daimler AG. The long-term contracts and the supporting Daimler guarantee provide for full recovery of the Company’s investment in the event of early termination or default. Chrysler has announced the closure of one site that is under a long-term service contract with the Company. Through December 31, 2009, to the extent that Chrysler has not been performing in accordance with its contracts, Daimler has been performing under its guarantee. Therefore, the Company believes that it will recover its investment in the event of a facility closure or a Chrysler default.
 
The Company determined that the GM and Chrysler bankruptcy filings were triggering events to assess certain automotive-related long-lived assets for impairment and as of June 30, 2009, the Company performed an impairment analysis on these assets. Based on its undiscounted cash flow projections and fair value calculations, the Company determined that it did not have an impairment loss at June 30, 2009. We also determined that we did not have an other than temporary decline in our Chrysler-related equity investment. There were no new events occurring during the third and fourth quarters that would negatively impact the assumptions made for the second quarter impairment analysis. Therefore, no triggering events were identified during the remainder of 2009. The Company’s assumptions and conclusions may change in the future, and we could have an impairment loss if certain facilities are not utilized as currently anticipated.


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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 $58 million in 2009, $24 million in 2008, and $76 million in 2007. Postretirement benefits costs for all plans were $205 million in 2009, $142 million in 2008 and $188 million in 2007. Pension and postretirement benefits costs for 2009 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 2010 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment management of 45% in equity markets, 25% in fixed income markets, and 30% 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 2010. 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. Current accounting rules provide that the MRV of plan assets can 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 recognized. Financial markets in 2009 contributed to our investment performance resulting in unrecognized net gains. As of December 31, 2009, we had $612 million 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 decreased from 6.9% at December 31, 2008 to 5.9% at December 31, 2009. We estimate that our 2010 total pension costs will approximate $110 million compared to $58 million in 2009 due to 2008 financial market losses and a decreased discount rate, partially offset by substantial 2009 and planned 2010 contributions coupled with greater than expected 2009 financial market returns. Our 2010 postretirement benefit costs will approximate $167 million compared to $205 million in 2009 primarily due to company specific health care trends and favorable 2009 investment returns, mitigated by a decreased discount rate. 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 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


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January 1, 2009. In April 2005, the MPSC approved the deferral of the non-capitalized portion of MichCon’s negative pension expense. MichCon records 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 2009 pension costs by approximately $29 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2009 pension costs by approximately $15 million. Lowering the health care cost trend assumptions by one percentage point would have decreased our postretirement benefit service and interest costs for 2009 by approximately $30 million.
 
In 2008, 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 value of our pension and postretirement benefit plan assets was $3.4 billion at December 31, 2009 and $2.8 billion at December 31, 2008. At December 31, 2009 our pension plans were underfunded by $887 million and our other postretirement benefit plans were underfunded by $1.3 billion. The 2009 and 2008 funding levels were generally similar because of positive investment performance returns and plan sponsor contributions in 2009, largely offset by the decreased discount rates.
 
Pension and postretirement costs and pension cash funding requirements may increase in future years without typical returns in the financial markets. We made contributions to our pension plans of $200 million and $100 million in 2009 and 2008, respectively. Also, we contributed $100 million to our pension plans in January 2010. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making up to an additional $100 million contribution to our pension plans in 2010 and up to $1.1 billion over the next five years. We made postretirement benefit plan contributions of $205 million and $116 million in 2009 and 2008, respectively. 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 2010 and, subject to MPSC funding requirements, up to $765 million over the next five years. The planned contributions will be made in cash, DTE Energy common stock or a combination of cash and stock.
 
See Note 21 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.
 
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, 2009, this IBNR liability was approximately $38 million.


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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. 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.
 
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. We believe the resulting tax reserve balances as of December 31, 2009 and December 31, 2008 are appropriately accounted. 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 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
NEW ACCOUNTING PRONOUNCEMENTS
 
See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
FAIR VALUE
 
Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Contracts we typically classify as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign exchange contracts. Items we do not generally account for as derivatives include proprietary gas inventory, gas storage and transportation arrangements, and gas and oil reserves. See Notes 4 and 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
As a result of adherence to generally accepted accounting principles, the tables below do not include the expected earnings impact of 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 the timing differences will reverse at the time of physical delivery and/or settlement.
 
The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its 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). The following tables contain the four categories of activities 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.


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  •  Structured Contracts — Represents derivative activity transacted by originating hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers. Substantially all of this activity represents full requirements contracts, whereby the hedged percentage is largely based on estimated load requirements.
 
  •  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 — Includes 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. Other also includes derivative activity at Detroit Edison related to FTR’s and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative assets or liabilities, with an offset to Regulatory assets or liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.
 
The following tables provide details on changes in our MTM net asset (or liability) position during 2009:
 
                                         
    Economic
    Structured
    Proprietary
             
    Hedges     Contracts     Trading     Other     Total  
    (in Millions)  
 
MTM at December 31, 2008
  $ 18     $ (222 )   $ 22     $ 9     $ (173 )
                                         
Reclassify to realized upon settlement
    (23 )     98       (198 )     (8 )     (131 )
Changes in fair value recorded to income
    9       (32 )     203             180  
                                         
Amounts recorded to unrealized income
    (14 )     66       5       (8 )     49  
Changes in fair value recorded in regulatory liabilities
                      (16 )     (16 )
Amounts recorded in other comprehensive income, pretax
                      5       5  
Change in collateral held by others
    9       21       68             98  
Option premiums paid and other
          3       (65 )     6       (56 )
                                         
MTM at December 31, 2009
  $ 13     $ (132 )   $ 30     $ (4 )   $ (93 )
                                         
 
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, 2009. 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
  $ 11     $ 171     $ 27     $ (4 )   $ 4     $ 209  
Noncurrent assets
    8       104       5       (1 )           116  
                                                 
Total MTM assets
    19       275       32       (5 )     4       325  
                                                 
Current liabilities
    (5 )     (218 )     4       4       (5 )     (220 )
Noncurrent liabilities
    (1 )     (189 )     (6 )     1       (3 )     (198 )
                                                 
Total MTM liabilities
    (6 )     (407 )     (2 )     5       (8 )     (418 )
                                                 
Total MTM net assets (liabilities)
  $ 13     $ (132 )   $ 30     $     $ (4 )   $ (93 )
                                                 
 
The table below shows the maturity of our MTM positions:
 
                                         
                      2013
       
                      and
    Total Fair
 
Source of Fair Value
  2010     2011     2012     Beyond     Value  
    (in Millions)  
 
Economic Hedges
  $ 6     $ (3 )   $ (4 )   $ 14     $ 13  
Structured Contracts
    (45 )     (35 )     (22 )     (30 )     (132 )
Proprietary Trading
    29       5       2       (6 )     30  
Other
    (1 )     (3 )                 (4 )
                                         
Total
  $ (11 )   $ (36 )   $ (24 )   $ (22 )   $ (93 )
                                         
 
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. However, the Company does not bear significant exposure to earnings risk as such changes are included in the form of PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas, storage sales revenue and uncollectible expenses at the Gas Utility. Gas Utility manages its market price risk related to storage sales revenue primarily through the sale of long-term storage contracts. The Company has tracking mechanisms to mitigate a portion of losses related to uncollectible accounts receivable at MichCon and Detroit Edison. 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 Gas Storage and Pipelines business segment has limited exposure to natural gas price fluctuations and manages its exposure through the sale of long-term storage and transportation contracts.
 
Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we may use forward energy and futures contracts.
 
Our Power and Industrial Projects business segment is subject to electricity, natural gas, coal and coal-based product price risk and other risks associated with the weakened U.S. economy. To the extent that


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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.
 
Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign exchange 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.
 
Credit Risk
 
Bankruptcies
 
The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.
 
The Company’s utilities and certain non-utility businesses provide services to the domestic automotive industry, including GM, Ford Motor Company (Ford) and Chrysler and many of their vendors and suppliers. Chrysler filed for bankruptcy protection on April 30, 2009. We have reserved approximately $9 million of pre-petition accounts receivable related to Chrysler as of December 31, 2009. GM filed for bankruptcy protection on June 1, 2009. We have reserved or written off approximately $5 million of pre-petition accounts and notes receivable related to GM as of December 31, 2009. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact the Company’s operating revenues in future periods. In 2009, GM and Chrysler each represented two percent of our annual electric sales volumes, respectively. GM and Chrysler have an immaterial impact to MichCon’s revenues.
 
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, 2009:
 
                         
    Credit Exposure
             
    Before Cash
    Cash
    Net Credit
 
    Collateral     Collateral     Exposure  
    (in Millions)  
 
Investment Grade(1)
                       
A− and Greater
  $ 254     $ (12 )   $ 242  
BBB+ and BBB
    177             177  
BBB-
    54             54  
                         
Total Investment Grade
    485       (12 )     473  
Non-investment grade(2)
    2             2  
Internally Rated — investment grade(3)
    99             99  
Internally Rated — non-investment grade(4)
    10             10  
                         
Total
  $ 596     $ (12 )   $ 584  
                         
 
 
(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 29 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 less than one 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 14 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 less than two 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, 2009, we had a floating rate debt-to-total debt ratio of approximately five percent (excluding securitized debt).
 
Foreign Exchange Risk
 
The Company has foreign 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 exchange fluctuations, we have entered into a series of exchange forward contracts through January 2013. Additionally, we may enter into fair value exchange hedges to mitigate changes in the value of contracts or loans.
 
Summary of Sensitivity Analysis
 
The Company performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign exchange forward contracts. The commodity contracts and foreign exchange risk


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listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2009 and 2008 by a hypothetical 10% and calculating the resulting change in the fair values.
 
The results of the sensitivity analysis calculations as of December 31, 2009 and 2008:
 
                                     
    Assuming a
    Assuming a
     
    10% Increase in Rates     10% Decrease in Rates      
    As of December 31,     As of December 31,      
Activity
  2009     2008     2009     2008     Change in the Fair Value of
          (in Millions)            
 
Coal Contracts
  $     $ 1     $     $ (1 )   Commodity contracts
Gas Contracts
  $ (2 )   $ (13 )   $ 1     $ 13     Commodity contracts
Oil Contracts
  $ 1     $ 1     $ (1 )   $ (1 )   Commodity contracts
Power Contracts
  $ (3 )   $ 3     $ 2     $ (2 )   Commodity contracts
Interest Rate Risk
  $ (290 )   $ (317 )   $ 313     $ 346     Long-term debt
Foreign Exchange Risk
  $ 2     $ 5     $ (2 )   $ (5 )   Forward contracts
Discount Rates
  $     $ 1     $     $ (1 )   Commodity contracts
 
For further discussion of market risk, see Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


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Item 8.   Financial Statements and Supplementary Data
 
The following consolidated financial statements and financial statement schedule are included herein.
 
         
    Page
 
    64  
Consolidated Financial Statements
       
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    68  
    70  
    71  
    72  
    73  
    73  
    74  
    79  
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    87  
    92  
    93  
    94  
    94  
    96  
    97  
    98  
    107  
    110  
    110  
    112  
    114  
    114  
    116  
    117  
    121  
    132  
    135  
    136  
    139  
Financial Statement Schedule
       
    151  


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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, 2009, 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 as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, 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.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Management of the Company has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, management concluded that, as of December 31, 2009, the Company’s internal control over financial reporting was effective based on those criteria.
 
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm who also audited the Company’s financial statements, as stated in their report which appears herein.
 
(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, 2009 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:
 
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of DTE Energy Company and its subsidiaries at December 31, 2009, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2009 listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, 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 opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated 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 the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
/s/ PricewaterhouseCoopers LLP
 
Detroit, Michigan
February 23, 2010


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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 statement of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2008, and the related consolidated statements of operations, cash flows, and changes in shareholders’ equity and comprehensive income for years ended December 31, 2008 and 2007. Our audits also included the 2008 and 2007 information in the financial statement schedules listed in the accompanying index. 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 the results of their operations and their cash flows for the years ended December 31, 2008 and 2007 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2008 and 2007 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.
 
/s/ Deloitte & Touche LLP
 
Detroit, Michigan
February 27, 2009
 
(August 20, 2009, as to the effects of the retrospective adoption of Accounting Standards Codification (“ASC”) 810-10 and ASC 260-10 as described in Note 3 to the consolidated financial statements)


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DTE Energy Company
 
Consolidated Statements of Operations
 
                         
    Year Ended December 31  
    2009     2008     2007  
    (in Millions, except per
 
    share amounts)  
 
Operating Revenues
  $ 8,014     $ 9,329     $ 8,475  
                         
Operating Expenses
                       
Fuel, purchased power and gas
    3,118       4,306       3,552  
Operation and maintenance
    2,372       2,694       2,892  
Depreciation, depletion and amortization
    1,020       901       932  
Taxes other than income
    275       304       357  
Gain on sale of non-utility business
          (128 )     (900 )
Other asset (gains) and losses, reserves and impairments, net
    (20 )     (11 )     37  
                         
      6,765       8,066       6,870  
                         
Operating Income
    1,249       1,263       1,605  
                         
Other (Income) and Deductions
                       
Interest expense
    545       503       533  
Interest income
    (19 )     (19 )     (25 )
Other income
    (102 )     (104 )     (93 )
Other expenses
    43       64       35  
                         
      467       444       450  
                         
Income Before Income Taxes
    782       819       1,155  
Income Tax Provision
    247       288       364  
                         
Income from Continuing Operations
    535       531       791  
Discontinued Operations Income (Loss), net of tax
          22       (4 )
                         
Net Income
    535       553       787  
Less: Net Income (Loss) Attributable to Noncontrolling Interests From
                       
Continuing operations
    3       5       4  
Discontinued operations
          2       (188 )
                         
      3       7       (184 )
                         
Net Income Attributable to DTE Energy Company
  $ 532     $ 546     $ 971  
                         
Basic Earnings per Common Share
                       
Income from continuing operations
  $ 3.24     $ 3.22     $ 4.62  
Discontinued operations
          .12       1.08  
                         
Total
  $ 3.24     $ 3.34     $ 5.70  
                         
Diluted Earnings per Common Share
                       
Income from continuing operations
  $ 3.24     $ 3.22     $ 4.61  
Discontinued operations
          .12       1.08  
                         
Total
  $ 3.24     $ 3.34     $ 5.69  
                         
Weighted Average Common Shares Outstanding
                       
Basic
    164       163       170  
Diluted
    164       163       171  
Dividends Declared per Common Share
  $ 2.12     $ 2.12     $ 2.12  
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Financial Position
 
                 
    December 31  
    2009     2008  
    (in Millions)  
 
ASSETS
Current Assets
               
Cash and cash equivalents
  $ 52     $ 86  
Restricted cash
    84       86  
Accounts receivable (less allowance for doubtful accounts of $262 and $265, respectively)
               
Customer
    1,438       1,666  
Other
    217       166  
Inventories
               
Fuel and gas
    309       333  
Materials and supplies
    200       206  
Deferred income taxes
    167       227  
Derivative assets
    209       316  
Other
    201       242  
                 
      2,877       3,328  
                 
Investments
               
Nuclear decommissioning trust funds
    817       685  
Other
    598       595  
                 
      1,415       1,280  
                 
Property
               
Property, plant and equipment
    20,588       20,065  
Less accumulated depreciation, depletion and amortization
    (8,157 )     (7,834 )
                 
      12,431       12,231  
                 
Other Assets
               
Goodwill
    2,024       2,037  
Regulatory assets
    4,110       4,231  
Securitized regulatory assets
    870       1,001  
Intangible assets
    54       70  
Notes receivable
    113       115  
Derivative assets
    116       140  
Other
    185       157  
                 
      7,472       7,751  
                 
Total Assets
  $ 24,195     $ 24,590  
                 
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Financial Position — (Continued)
 
                 
    December 31  
    2009     2008  
    (in Millions,
 
    except shares)  
 
LIABILITIES AND EQUITY
Current Liabilities
               
Accounts payable
  $ 723     $ 899  
Accrued interest
    114       119  
Dividends payable
    88       86  
Short-term borrowings
    327       744  
Current portion long-term debt, including capital leases
    671       362  
Derivative liabilities
    220       285  
Other
    502       518  
                 
      2,645       3,013  
                 
Long-Term Debt (net of current portion)
               
Mortgage bonds, notes and other
    6,237       6,458  
Securitization bonds
    793       932  
Trust preferred-linked securities
    289       289  
Capital lease obligations
    51       62  
                 
      7,370       7,741  
                 
Other Liabilities
               
Deferred income taxes
    2,096       1,958  
Regulatory liabilities
    1,337       1,202  
Asset retirement obligations
    1,420       1,340  
Unamortized investment tax credit
    85       96  
Derivative liabilities
    198       344  
Liabilities from transportation and storage contracts
    96       111  
Accrued pension liability
    881       871  
Accrued postretirement liability
    1,287       1,434  
Nuclear decommissioning
    136       114  
Other
    328       328  
                 
      7,864       7,798  
                 
Commitments and Contingencies (Notes 12 and 20)
               
Equity
               
Common stock, without par value, 400,000,000 shares authorized, 165,400,045 and 163,019,596 shares issued and outstanding, respectively
    3,257       3,175  
Retained earnings
    3,168       2,985  
Accumulated other comprehensive loss
    (147 )     (165 )
                 
Total DTE Energy Company Shareholders’ Equity
    6,278       5,995  
Noncontrolling interests
    38       43  
                 
Total Equity
    6,316       6,038  
                 
Total Liabilities and Equity
  $ 24,195     $ 24,590  
                 
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Cash Flows
 
                         
    Year Ended December 31  
    2009     2008     2007  
    (in Millions)  
 
Operating Activities
                       
Net income
  $ 535     $ 553     $ 787  
Adjustments to reconcile net income to net cash from operating activities:
                       
Depreciation, depletion and amortization
    1,020       899       926  
Deferred income taxes
    205       348       144  
Gain on sale of non-utility business
          (128 )     (900 )
Other asset (gains), losses and reserves, net
    (10 )     (4 )     (9 )
Gain on sale of interests in synfuel projects
          (31 )     (248 )
Impairment of synfuel projects
                4  
Contributions from synfuel partners
          14       229  
Changes in assets and liabilities, exclusive of changes shown separately (Note 23)
    69       (92 )     192  
                         
Net cash from operating activities
    1,819       1,559       1,125  
                         
Investing Activities
                       
Plant and equipment expenditures — utility
    (960 )     (1,183 )     (1,035 )
Plant and equipment expenditures — non-utility
    (75 )     (190 )     (264 )
Proceeds from sale of interests in synfuel projects
          84       447  
Refunds to synfuel partners
          (387 )     (115 )
Proceeds from sale of non-utility business
          253       1,262  
Proceeds from sale of other assets, net
    83       25       85  
Restricted cash for debt redemption
    2       54       6  
Proceeds from sale of nuclear decommissioning trust fund assets
    295       232       286  
Investment in nuclear decommissioning trust funds
    (315 )     (255 )     (323 )
Other investments
    (94 )     (156 )     (19 )
                         
Net cash from (used) for investing activities
    (1,064 )     (1,523 )     330  
                         
Financing Activities
                       
Issuance of long-term debt
    427       1,310       50  
Redemption of long-term debt
    (486 )     (446 )     (393 )
Repurchase of long-term debt
          (238 )      
Short-term borrowings, net
    (417 )     (340 )     (47 )
Issuance of common stock
    35              
Repurchase of common stock
          (16 )     (708 )
Dividends on common stock
    (348 )     (344 )     (364 )
Other
          (10 )     (6 )
                         
Net cash used for financing activities
    (789 )     (84 )     (1,468 )
                         
Net Decrease in Cash and Cash Equivalents
    (34 )     (48 )     (13 )
Cash and Cash Equivalents Reclassified (to) from Assets Held for Sale
          11       (11 )
Cash and Cash Equivalents at Beginning of Period
    86       123       147  
                         
Cash and Cash Equivalents at End of Period
  $ 52     $ 86     $ 123  
                         
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Changes in Equity
 
                                                 
                      Accumulated
             
                      Other
    Non-
       
    Common Stock     Retained
    Comprehensive
    Controlling
       
    Shares     Amount     Earnings     Loss     Interest     Total  
    (Dollars in millions, shares in Thousands)