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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, 2010
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
  48226-1279
(Address of principal executive offices)
  (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.  o.
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller Reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
On June 30, 2010, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $7.8 billion (based on the New York Stock Exchange closing price on such date). There were 169,443,420 shares of common stock outstanding at January 31, 2011.
 
Certain information in DTE Energy Company’s definitive Proxy Statement for its 2011 Annual Meeting of Common Shareholders to be held May 5, 2011, 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, 2010

TABLE OF CONTENTS
 
             
        Page
 
Definitions     1  
Forward-Looking Statements     3  
PART I
Items 1., 1A., 1B. & 2.   Business, Risk Factors, Unresolved Staff Comments and Properties     5  
Item 3.   Legal Proceedings     25  
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     56  
Item 8.   Financial Statements and Supplementary Data     59  
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     135  
Item 9A.   Controls and Procedures     135  
Item 9B.   Other Information     135  
 
PART III
Item 10.   Directors, Executive Officers and Corporate Governance     135  
Item 11.   Executive Compensation     135  
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     135  
Item 13.   Certain Relationships and Related Transactions, and Director Independence     135  
Item 14.   Principal Accountant Fees and Services     135  
 
PART IV
Item 15.   Exhibits and Financial Statement Schedules     135  
Signatures     147  
 EX-3.1
 EX-12.46
 EX-21.6
 EX-23.23
 EX-23.24
 EX-31.63
 EX-31.64
 EX-32.63
 EX-32.64
 EX-99.54
 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


Table of Contents

 
DEFINITIONS
 
ASC Accounting Standards Codification
 
ASU Accounting Standards Update
 
Company DTE Energy Company and any subsidiary companies
 
CIM A Choice Incentive Mechanism authorized by the MPSC that allows Detroit Edison to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales.
 
CTA Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
 
Customer Choice Michigan legislation giving customers 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
 
FTRs Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
 
GCR A Gas Cost Recovery mechanism authorized by the MPSC that allows MichCon to recover through rates its natural gas costs.
 
HCERA Health Care and Education Reconciliation Act of 2010
 
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.
 
MDNRE Michigan Department of Natural Resources and Environment
 
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.
 
NRC United States Nuclear Regulatory Commission
 
PPACA
Patient Protection and Affordable Care Act of 2010
 
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.


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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.
 
RDM A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas.
 
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.
 
Subsidiaries The direct and indirect subsidiaries of DTE Energy Company
 
Unconventional Gas Includes those gas and oil deposits that originated and are stored in coal bed, tight sandstone and shale formations.
 
VIE Variable Interest Entity
 
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.
 
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:
 
  •  economic conditions resulting in changes in 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 changes 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;
 
  •  the 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 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;
 
  •  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;


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  •  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, transportation, gathering, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity.
 
Our other segments are involved in 1) natural gas storage and pipelines; 2) unconventional gas and oil project development and production; 3) power and industrial projects; 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, transportation, gathering, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.


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Non-Utility Operations
 
  •  Gas Storage and Pipelines consists of natural gas storage and pipelines businesses.
 
  •  Unconventional Gas Production is engaged in unconventional gas and oil 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, renewable power generation, landfill gas recovery and coal transportation, marketing and trading.
 
  •  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 MDNRE. 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.
 
Revenue by Service
 
                         
    2010     2009     2008  
    (In millions)  
 
Residential
  $ 2,052     $ 1,820     $ 1,726  
Commercial
    1,629       1,702       1,753  
Industrial
    688       730       894  
Other
    479       299       289  
                         
Subtotal
    4,848       4,551       4,662  
Interconnection sales(1)
    145       163       212  
                         
Total Revenue
  $ 4,993     $ 4,714     $ 4,874  
                         
 
 
(1) Represents power that is not distributed by Detroit Edison.


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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 long-term and short-term contracts for a total purchase of approximately 30 million tons of low-sulfur western coal to be delivered from 2011 through 2013 and approximately 5 million tons of Appalachian coal to be delivered from 2011 through 2012. All of these contracts have pricing schedules. We have approximately 98% of our 2011 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 our expected western rail requirements under contract for the next five years. All of our eastern coal rail requirements are under contract through 2012 and approximately 50% of this requirement is under contract in 2013. Our expected vessel transportation requirements for delivery of purchased coal to our generating facilities are under contract through 2014.
 
Detroit Edison participates in the energy market through MISO. We offer our generation in the market on a day-ahead, real-time and FTR 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.
 
In 2008, a renewable portfolio standard was established for Michigan electric providers targeting 10% of electricity sold to retail customers from renewable energy by 2015. Detroit Edison has approximately 251 MW of renewable energy under contract at December 31, 2010 representing approximately 4% of electricity sold to retail customers. Approximately 40 MW is in commercial operation at December 31, 2010 with an additional 211 MW expected in commercial operation in 2011 or early 2012.
 
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, 2010 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       1,044       9.5     1984 and 1985
Conners Creek
    Wayne       239       2.1     1951
Greenwood
    St. Clair       785       7.1     1979
Harbor Beach
    Huron       94       0.9     1968
Marysville
    St. Clair       84       0.8     1943 and 1947
Monroe(3)
    Monroe       3,027       27.6     1971, 1973 and 1974
River Rouge
    Wayne       523       4.8     1957 and 1958
St. Clair(4)
    St. Clair       1,368       12.5     1953, 1954, 1959, 1961 and 1969
Trenton Channel
    Wayne       698       6.4     1949 and 1968
                             
              7,862       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       1,087       9.9     1988
Hydroelectric Pumped Storage
Ludington(6)
    Mason       917       8.4     1973
                             
              10,967       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% 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 2010 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 674 distribution substations with a capacity of approximately 33,585,000 kilovolt-amperes (kVA) and approximately 412,100 line transformers with a capacity of approximately 23,849,000 kVA.
 
Circuit miles of electric distribution lines owned and in service as of December 31, 2010:
 
                 
    Circuit Miles  
Operating Voltage-Kilovolts (kV)   Overhead     Underground  
 
4.8 kV to 13.2 kV
    28,345       13,916  
24 kV
    181       696  
40 kV
    2,278       381  
120 kV
    54       13  
                 
      30,858       15,006  
                 


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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, an unrelated company, 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 and network reliability we continue to make capital investments in our generating plants and distribution system, which will improve plant availability, operating efficiencies and environmental compliance in areas that have a positive impact on reliability 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 are minimizing the impacts of changes in average customer usage through regulatory mechanisms which 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 10% of retail sales in 2010 and 3% of retail sales in 2009 and 2008. 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 2008 energy legislation enacted by the State of Michigan are adjusting 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. In addition, we have a Choice Incentive Mechanism, which is an over/under recovery mechanism that measures non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceed the baseline amount from Detroit Edison’s most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decrease below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. We expect that in 2011 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales.


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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
 
                         
    2010     2009     2008  
    (In millions)  
 
Gas sales
  $ 1,281     $ 1,443     $ 1,824  
End user transportation
    185       144       143  
Intermediate transportation
    69       69       73  
Storage and other
    113       132       112  
                         
Total Revenue
  $ 1,648     $ 1,788     $ 2,152  
                         
 
  •  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 is 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 transportation 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. We are minimizing the impacts of changes in average customer usage through regulatory mechanisms which decouple our revenue levels from sales volumes.
 
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 2.4 Bcf, with approximately 65% of the volume coming from underground storage for 2010. 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


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requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
 
We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to the New York Mercantile Exchange and published price indices to approximate current market prices combined with MPSC approved fixed price supplies with varying terms and volumes through 2014.
 
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
 
Vector Pipeline L.P. 
    50       2012  
Great Lakes Gas Transmission L.P. 
    80       2013  
Viking Gas Transmission Company
    51       2013  
ANR Pipeline Company
    195       2017  
Panhandle Eastern Pipeline Company
    75       2029  
 
Properties
 
We own distribution, storage and transportation properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately 1,036,000 service lines and approximately 1,319,000 active meters. We own approximately 2,000 miles of transportation 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 134 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 transportation 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 602 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 the 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 storage and transportation facilities in Michigan as intrastate facilities regulated by the MPSC and provides intrastate storage and transportation services pursuant to an MPSC-approved tariff.
 
MichCon also provides interstate storage and transportation services in accordance with an Operating Statement on file with the FERC. The FERC’s jurisdiction is limited and extends to the rates, non-discriminatory requirements and terms and conditions applicable to storage and transportation provided by MichCon in interstate markets. FERC granted MichCon authority to provide storage and related services in interstate commerce at market-based rates. MichCon provides transportation services in interstate commerce at cost-based rates approved by the MPSC and filed 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. We expect future sales volumes to decline as a result of economic conditions, a decrease in the number of customers, reduced natural gas usage by customers due to more efficient furnaces and appliances, and an increased emphasis on conservation of energy usage. We are minimizing the impacts of changes in average customer usage through regulatory mechanisms which 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 transportation pipeline system has enabled us to market 400 to 500 Bcf annually for intermediate storage and transportation 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 transportation 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   IL, IN, 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. 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 and oil exploration, development and production primarily within the Barnett shale in north Texas. Our acreage covers an area that produces high Btu gas which provides a significant contribution to revenues from the value of natural gas liquids extracted from the gas stream. During this period of low natural gas prices, these natural gas liquids, with prices correlated to crude oil prices, have provided a significant increase to our realized wellhead price. Our drilling efforts this year have and will continue to target liquids rich gas and oil producing locations. Total capital investment of $26 million and production of 5 Bcfe remained consistent with 2009. We executed on leasing opportunities to optimize our existing portfolio by acquiring acreage at attractive prices in 2010, bringing our total net acreage position to 70,246 acres, net of impairments and expirations.


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Properties and Other
 
The following information pertains to our interests in the Barnett shale as of December 31:
 
                         
    2010   2009   2008
 
Producing Wells(1)(2)(3)
    194       174       162  
Developed Lease Acreage(1)(3)(4)
    15,928       14,968       14,248  
Undeveloped Lease Acreage(1)(3)(5)
    54,318       48,399       46,187  
Production Volume (Bcfe)
    4.8       5.0       5.0  
Proved Reserves (Bcfe)(6)
    201       234       167  
Capital Expenditures (in millions)(3)
  $ 26     $ 26     $ 100  
Future Undiscounted Cash Flows (in millions)(7)
  $ 478     $ 392     $ 324  
Average Gas Price, excluding hedge contracts (per Mcf)
  $ 5.99     $ 4.34     $ 8.69  
Average Oil Price, excluding hedge contracts (per Barrel)
  $ 76.41     $ 58.47     $ 90.27  
 
 
(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 decrease in proved reserves in 2010 is primarily due to removal of reserves that exceeded the five-year development limit for the Proved Undeveloped classification, and other revisions to estimates. The increases in proved reserves in 2009 are 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
 
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 when conditions are appropriate. Our strategy for 2011 is to maintain our focus on reducing operating expenses and optimizing production volume. Given the current outlook of low natural gas prices, drilling efforts will continue to target liquids rich gas and oil production. During 2011, we expect total capital investment of $25 million to drill approximately 20 new wells and continue to acquire select acreage and achieve production of approximately 6 Bcfe of natural gas, compared with 5 Bcfe in 2010.
 
We manage and operate our properties to maximize returns on investment and increase earnings. We expect to continue acquiring additional acreage at attractive prices providing opportunities to create value at low cost. We will target properties with liquids rich gas and oil potential and our drilling efforts will continue to be focused on these areas. Due to increased activity in other shale plays throughout the country, the availability of service providers has decreased somewhat. However, we do not expect this to have a significant impact on our drilling plans or operations, since most oilfield services have been secured for the next 12 months.
 
From time to time, we may use financial derivative contracts to manage a portion of our exposure to changes in the price of natural gas and oil on our forecasted sales volume. At December 31, 2010, we had no long-term fixed


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price contracts relating to natural gas and had the following financial contracts in place with our Energy Trading affiliate related to our projected oil production:
 
         
    2011
 
Oil Volume (in MBbl)
    72  
Price (in Bbl)
  $ 93.28  
 
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 as follows:
 
Steel, Steel Industry Fuel, and Petroleum Coke:  We produce metallurgical coke from two coke batteries with a capacity of 1.4 million tons per year. We have an investment in a third coke battery with a capacity of 1.2 million tons per year. We are investors in steel industry fuel entities which sell steel industry fuel 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 2010. The ability to generate tax credits from the steel industry fuel process expired at December 31, 2010. We also provide pulverized coal and petroleum coke to the steel, pulp and paper, and other industries.
 
Onsite Energy:  We provide power generation, steam production, chilled water production, wastewater treatment and compressed air supply to industrial customers. This business segment provides utility-type services using project assets usually located on or near the customers’ premises in the automotive, airport and other industries.
 
Wholesale Power and Renewables:  We own and operate three biomass-fired electric generating plants with a capacity of 133 MWs. We own two coal-fired power plants currently undergoing conversions to biomass with expected in-service dates of the fourth quarter of 2011 and the first quarter of 2013. We own one gas-fired peaking electric generating plant. The electric output is sold under long term power purchase agreements. We also 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.
 
Reduced Emission Fuel:  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 reductions in Nitrogen Oxide (NO) and Mercury (Hg) emissions. We began generating production tax credits from these facilities beginning in 2009 which will continue through 2019 upon achieving certain criteria, including entering into transactions with unrelated equity partners or third-party customers for the reduced emission fuel. We continue to optimize these facilities by seeking investors for facilities operating at Detroit Edison sites, and intend to relocate other facilities to alternative sites which may provide increased production and emission reduction opportunities in 2011 and future years. In January 2011, the Company entered into an agreement to sell a membership interest in one of these reduced emission fuel facilities that is located at a Detroit Edison site.
 
Coal Services:  The business provides coal transportation and related services including fuel to our customers with significant energy requirements which include electric utilities, merchant power producers, integrated steel mills and large industrial companies. We specialize in minimizing fuel costs and maximizing reliability of supply for those energy-intensive customers. We own and operate a coal transloading terminal which provides storage and blending for our customers. We also engage in coal marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emission allowances.


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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 and Petroleum Coke
  IN & MS   Metallurgical Coke Supply/Steel Industry Fuels, and Pulverized Petroleum Coke
         
On-Site Energy
       
Automotive
  Various sites in   Electric Distribution, Chilled
    MI, IN, OH,
NY & PA
  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
         
Wholesale Power & Renewables
       
Pulp and Paper
  AL   Electric Generation and Steam
Power Generation
  MI   Electric Peaking
Renewables
  CA & WI   Electric Generation
Landfill Gas Recovery
  Various U.S. Sites   Electric generation
         
Other Industries
       
Reduced Emission Fuel
  MI   Reduced Emission Fuel Supply
Coal Terminaling
  IL   Coal Terminal and Blending
 
                         
    2010     2009     2008  
    (In millions)  
 
Production Tax Credits Generated (Allocated to DTE Energy)
                       
Coke Battery(1)
  $     $ 5     $ 5  
Steel Industry Fuels(2)
    29       4        
Power Generation
    2       2       2  
Landfill Gas Recovery
    1       1        
Reduced Emission Fuel
    1              
 
 
(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 expired on December 31, 2010.
 
Regulation
 
Certain electric generating facilities within Power and Industrial Projects have market-based rate authority from the FERC to sell power. The facilities are subject to FERC reporting requirements and market behavior rules. Certain Power and Industrial projects are also subject to the applicable laws, rules and regulations related to the Commodity Futures Trading Commission, U.S. Department of Homeland Security and Department of Energy.


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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 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, new and pending legislation, 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:
 
  •  Monetizing and relocating our reduced emission fuel facilities;
 
  •  Acquiring and developing landfill gas recovery facilities, renewable energy projects, and other energy projects which may qualify for tax credits; and
 
  •  Providing operating services to owners of industrial and power plants.
 
Our Coal Transportation and Marketing business will continue to leverage its existing business in 2011. Trends such as railroad and mining consolidation and the lack of certainty in developing new mines could have an impact on how we compete in the future. Effective January 1, 2011, our existing long-term rail transportation contract, at rates significantly below the current market, expired and we anticipate a decrease in transportation-related revenue of approximately $130 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.
 
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. 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. 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. These financial instruments are generally 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 Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives; whereas, gas inventory, power transmission, pipeline transportation 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. The segment’s 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.
 
Regulation
 
Energy Trading has market-based rate authority from the FERC to sell power and blanket authority from the FERC to sell natural gas at market prices. Energy Trading is subject to FERC reporting requirements and market


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behavior rules. Energy Trading is also subject to the applicable laws, rules and regulations related to the Commodity Futures Trading Commission, U.S. Department of Homeland Security and Department of Energy.
 
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.
 
ENVIRONMENTAL MATTERS
 
We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers. The following table summarizes our estimated significant future environmental expenditures based upon current regulations:
 
                                 
    Electric     Gas     Non-Utility     Total  
    (In millions)  
 
Air
  $ 2,100     $     $     $ 2,100  
Water
    55             13       68  
MGP sites
    4       36             40  
Other sites
    21       1             22  
                                 
Estimated total future expenditures through 2020
  $ 2,180     $ 37     $ 13     $ 2,230  
                                 
Estimated 2011 expenditures
  $ 239     $ 11     $ 3     $ 253  
                                 
Estimated 2012 expenditures
  $ 276     $ 7     $ 7     $ 290  
                                 
 
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, the 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 operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.


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On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison’s fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA’s motion for preliminary injunction was denied and the liability phase of the civil suit has been scheduled for trial in May 2011.
 
DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the civil action, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company 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 completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA’s use of this provision in determining best technology available for reducing environmental impacts. Concurrently, the EPA continues to develop a revised rule, a draft of which is expected to be published in the first quarter of 2011, with a final rule scheduled for mid-2012. The EPA has also issued 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, 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.
 
Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.
 
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.


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The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either, to designate coal ash as a “Hazardous Waste” as defined by RCRA or to regulate coal ash as non-hazardous waste under RCRA. However, agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the 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 significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.
 
Non-Utility
 
The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants.
 
The Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a Notice of Violation in June of 2007 alleging potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDNRE concerning visible emissions readings that resulted from the Company self reporting to the MDNRE questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the impact of this investigation.
 
The Company is also in the process of settling historical air and water violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the impact of this settlement. The Company received two notices of violation from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.
 
Global Climate Change
 
Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. Despite passage of a greenhouse gas cap and trade bill by the U.S. House in June 2009, the Senate has been unable to pass a similar climate bill. A greenhouse gas cap and trade program is not expected to be included in energy or climate bills to be considered by the 112th Congress. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. The EPA regulation of greenhouse gases (GHGs) begins in 2011 requiring the best available control technology (BACT) for major sources or modifications to existing major sources that cause significant increases in GHG emissions. The impact of this rule is uncertain until BACT is better defined by the permitting agencies. 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, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. 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 Management’s Discussion and Analysis in Item 7 of this Report.


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EMPLOYEES
 
We had approximately 9,800 employees as of December 31, 2010, of which approximately 5,000 were represented by unions. There are several bargaining units for the Company’s represented employees. In the 2010 third quarter, a new three-year agreement was ratified covering approximately 3,800 represented employees. The majority of the remaining represented employees are under contracts that expire in June 2011 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 could result in decreased earnings and cash flow.
 
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 changed 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 elected a new governor and legislature in November 2010 and we cannot predict whether the resulting 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 base 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 2008 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


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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 full service electric price changes.
 
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.
 
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 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 2012 and 2013. 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,


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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.
 
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 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 businesses. 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 energy also impacts the market for our non-utility businesses that compete with utilities and alternative electric suppliers.
 
The supply and/or price of 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


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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 great care is exercised in utilizing historical information and assumptions to develop reasonable estimates of future production and cash flow, we cannot provide absolute assurance that our estimates of our Barnett gas reserves are accurate. 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 coke production, landfill gas recovery; biomass fired electric generation, reduced emission fuel, steel industry fuel and gas production operations. All production tax credits taken after 2008 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 rely on cash flows from subsidiaries.  DTE Energy is a holding company. Cash flows from our utility and non-utility subsidiaries are required to pay interest expenses and dividends on DTE Energy debt and securities. Should a major subsidiary not be able to pay dividends or transfer cash flows to DTE Energy, our ability to pay interest and dividends would be restricted.
 
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.


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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.
 
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, 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.
 
A work interruption may adversely affect us.  Unions represent approximately 5,000 of our employees. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.
 
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations.  Our business is dependent on our ability to recruit, retain, and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 3.   Legal Proceedings
 
We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such 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 periods 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


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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 of Detroit Edison’s power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. In June 2010, the EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant.
 
On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison’s fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA’s motion for preliminary injunction was denied and the liability phase of the civil suit has been scheduled for trial in May 2011.
 
DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the civil action, Detroit Edison could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of this matter, or the timing of its resolution.
 
In October 2010, the Company received a Notice of Violation from the MDNRE alleging that the Michigan coke battery facility violated the visible emission readings and quench water sampling requirements under applicable National Emissions Standards for Hazardous Air Pollutants regulations. This Notice of Violation resulted from the Company self reporting to the MDNRE and the EPA questionable activities by an employee of a contractor hired by the Company to perform visible emissions readings and quench water sampling. The information provided by contractor was used by the Company in filing certain reports with the MDNRE and the EPA. The Company has ceased using the contractor for these activities, has retained a new certified contractor to perform the required activities and implemented standard operating procedures designed to prevent a reoccurrence of such a situation. At this time, the Company cannot predict the outcome or financial impact of this issue.
 
In December 2010, the Company received a Notice of Violation from the Detroit Water and Sewerage Department (DWSD) alleging that effluent discharges from the Michigan coke battery facility violated the City of Detroit Ordinance, the General Pre-Treatment Standards and the terms of a Consent Judgment entered between the Company and the DWSD with respect to the Michigan coke battery facility in March 2009. The Company has settled similar alleged violations with respect to the Michigan coke battery facility with the DWSD in the past. The Company has installed a biological waste water treatment plant at the Michigan coke battery facility in accordance with the Consent Judgement that is designed to meet the effluent limitations and is in the process of optimizing plant performance to minimize any future excursions of the Ordinance and the General Pre-Treatment Standards. The DWSD has demanded payment of $176,000 in penalties in connection with the alleged violations. The Company is actively pursuing a settlement with DWSD, but we cannot predict the outcome or financial impact of this matter.
 
In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not


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issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company will be required to complete ceramic welding repairs to the coke battery facility and to make repairs to the waste water treatment facility at the coke battery facility. The Company will also be required to pay a fine in connection with the settlement of these historic violations. At this time, the Company cannot predict the outcome or financial impact of this settlement 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.
 
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  
 
  2010                              
        First   $ 45.93     $ 41.25     $ 0.530  
        Second   $ 49.05     $ 43.00     $ 0.530  
        Third   $ 49.06     $ 44.93     $ 0.560  
        Fourth   $ 47.66     $ 44.27     $ 0.560  
  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  
 
At December 31, 2010, there were 169,428,406 shares of our common stock outstanding. These shares were held by a total of 74,822 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 $360 million in 2010, $348 million in 2009, and $344 million in 2008. 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, 2010.
 
                         
    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
    4,827,457     $ 41.09       2,806,555  
 
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, 2010:
 
                                         
                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     per Share     Programs  
 
01/01/10 — 01/31/10
                             
02/01/10 — 02/28/10
                             
03/01/10 — 03/31/10
    55,000     $ 45.07                    
04/01/10 — 04/30/10
                             
05/01/10 — 05/31/10
    85,000       48.33                    
06/01/10 — 06/30/10
                             
07/01/10 — 07/31/10
                             
08/01/10 — 08/31/10
    35,000       46.40                    
09/01/10 — 09/30/10
    44,000       47.89                    
10/01/10 — 10/31/10
                             
11/01/10 — 11/30/10
    15,000       45.34                    
12/01/10 — 12/31/10
                             
                                         
Total
    234,000                                
                                         
 
 
(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.


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COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN
 
Total Return To Shareholders
(Includes reinvestment of dividends)
 
                                         
    Annual Return Percentage
    Year Ended December 31
Company/Index   2006   2007   2008   2009   2010
DTE Energy Company
    17.66       (5.03 )     (14.37 )     30.08       9.06  
                                         
S&P 500 Index
    15.79       5.49       (37.00 )     26.46       15.06  
                                         
S&P 500 Multi-Utilities Index
    16.74       10.86       (24.34 )     20.93       11.08  
                                         
 
                                                 
    Indexed Returns
    Year Ended December 31
    Base
                   
    Period
                   
Company/Index   2005   2006   2007   2008   2009   2010
DTE Energy Company
    100       117.66       111.74       95.68       124.46       135.73  
                                                 
S&P 500 Index
    100       115.79       122.16       76.96       97.33       111.99  
                                                 
S&P 500 Multi-Utilities Index
    100       116.74       129.42       97.92       118.41       131.53  
                                                 
 
Comparison of Cumulative Five Year Total Return
 
(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.
 
                                         
    2010     2009     2008     2007     2006  
    (In millions, except per share amounts)  
 
Operating Revenues
  $ 8,557     $ 8,014     $ 9,329     $ 8,475     $ 8,157  
                                         
Net Income Attributable to DTE Energy Company
                                       
Income from continuing operations(1)
  $ 630     $ 532     $ 526     $ 787     $ 389  
Discontinued operations
                20       184       43  
Cumulative effect of accounting changes
                            1  
                                         
Net Income Attributable to DTE Energy Company
  $ 630     $ 532     $ 546     $ 971     $ 433  
                                         
Diluted Earnings Per Common Share
                                       
Income from continuing operations
  $ 3.74     $ 3.24     $ 3.22     $ 4.61     $ 2.18  
Discontinued operations
                .12       1.08       .24  
Cumulative effect of accounting changes
                            .01  
                                         
Diluted Earnings Per Common Share
  $ 3.74     $ 3.24     $ 3.34     $ 5.69     $ 2.43  
                                         
Financial Information
                                       
Dividends declared per share of common stock
  $ 2.18     $ 2.12     $ 2.12     $ 2.12     $ 2.075  
Total assets
  $ 24,896     $ 24,195     $ 24,590     $ 23,742     $ 23,785  
Long-term debt, including capital leases
  $ 7,089     $ 7,370     $ 7,741     $ 6,971     $ 7,474  
Shareholders’ equity
  $ 6,722     $ 6,278     $ 5,995     $ 5,853     $ 5,849  
 
 
(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 2010 operating revenues in excess of $8 billion and approximately $25 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:
 
                         
    2010   2009   2008
    (In millions, except per share amounts)
 
Net income attributable to DTE Energy Company
  $ 630     $ 532     $ 546  
Diluted earnings per common share
  $ 3.74     $ 3.24     $ 3.34  
 
The increase in 2010 Net income attributable to DTE Energy as compared to 2009 was primarily due to improved results in the Electric and Gas Utilities and in the Power and Industrial Projects segment, partially offset by lower earnings in Energy Trading. The decrease in Net income attributable to DTE Energy in 2009 from 2008 was primarily due to an $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 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, transportation, gathering, 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.
 
Detroit Edison has experienced decreased electric sales in 2010 driven primarily by a decrease in commercial sales, partially offset by higher residential and industrial sales. Commercial sales continue to be lower due primarily to customers participating in the electric Customer Choice program. The residential sales increase is a result of warmer summer weather. Industrial sales are higher due to increased demand from customers in the automotive and steel industries and their related suppliers and other ancillary businesses. The impact of customers participating in the electric Customer Choice program is mitigated by the CIM, an over/under recovery mechanism which measures non-fuel revenues that are lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceed the baseline amount from Detroit Edison’s most recent rate case, 90 percent


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of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decrease below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. MichCon’s sales were lower due primarily to a decrease in the number of customers, reduced natural gas usage by customers due to economic conditions and an increased emphasis on conservation of energy usage.
 
We have RDMs in place at both utilities. The RDMs are designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas. The January 2010 MPSC order in Detroit Edison’s 2009 rate case provided for, among other items, the implementation of a pilot electric RDM effective February 1, 2010. The electric RDM enables Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The June 2010 MPSC order in MichCon’s 2009 rate case provided for, among other items, the implementation of a pilot gas RDM effective July 1, 2010. The gas RDM enables MichCon to recover or refund the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base average sales per customer established in the MPSC order. The RDMs for Detroit Edison and MichCon address changes in customer usage due to general economic conditions and conservation, but do not shield the utilities from the impacts of lost customers. In addition, the pilot electric RDM materially shields Detroit Edison from the impact of weather on customer usage. The pilot gas RDM does not shield MichCon from the impact of weather on customer usage. The electric and gas RDMs are subject to review by the MPSC after the initial one-year pilot programs.
 
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. We have taken actions to manage the level of past due receivables, including customer assistance forums, contracting with collection agencies, working with Michigan officials and others to increase the share of low-income funding allocated to our customers, and increasing customer disconnections. As a result of actions taken to manage the level of past due receivables, arrears were reduced in 2010 in our electric and gas utilities. Detroit Edison has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense for each year and the $66 million level reflected in base rates. In the June 2010 MPSC rate order, the base amount of MichCon’s uncollectible expense tracking mechanism was increased prospectively from $37 million to $70 million and MichCon’s portion of recovery or refund of the expenses above or below the base amount was modified to 80 percent from 90 percent. The Detroit Edison and MichCon uncollectible tracking mechanisms require annual reconciliation proceedings before the MPSC.
 
                         
    2010     2009     2008  
    (In millions)  
 
Uncollectible Expense
                       
Detroit Edison
  $ 58     $ 78     $ 87  
MichCon
    58       93       126  
                         
    $ 116     $ 171     $ 213  
                         
 
We are continuing our efforts to identify opportunities to improve cash flow at our utility operations through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects. We are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength. See the Capital Resources and Liquidity section in this Management’s Discussion and Analysis for further discussion of our liquidity outlook.
 
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.


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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 Eastern Canada and the Northeast U.S. regions. Our Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. In addition, Millennium Pipeline is well positioned for growth related to the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York.
 
Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production primarily within the Barnett shale in north Texas. Our acreage covers an area that produces high Btu gas which provides a significant contribution to revenues from the value of natural gas liquids extracted from the gas stream. During this period of low natural gas prices, these natural gas liquids, with prices correlated to crude oil prices, have provided a significant increase to our realized wellhead price. Our drilling efforts have and will continue to target liquids rich gas and oil producing locations. We continue to develop our holdings and to seek opportunities for additional monetization of select properties, when conditions are appropriate.
 
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, marketing and trading services; 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 renewable power generation, landfill gas recovery, reduced emission fuel 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.
 
CAPITAL INVESTMENTS
 
We anticipate significant capital investments during the next three years concentrated primarily in Detroit Edison.
 
         
    2011-2013  
    (In billions)  
 
Capital Investments
       
Detroit Edison
  $ 3.4 — 3.8  
MichCon
    0.5 — 0.6  
Non-Utility
    0.6 — 0.9  
         
    $ 4.5 — 5.3  
 
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. For both Detroit Edison and MichCon we plan to seek regulatory approval in general rate case filings to include these capital expenditures within our regulatory rate base consistent with prior general rate case filing treatment. Detroit Edison is required to implement a 20-year renewable energy plan to address the provisions of Michigan Public Act 295 of 2008, with the goals of delivering cleaner renewable electric generation to its customers, further diversifying Detroit Edison’s and the State of Michigan’s sources of electric supply and addressing the state and national goals of increasing energy independence. Detroit Edison will seek separate regulatory approval and recovery of these renewable capital expenditures within our regulatory rate base through our renewable energy plan filings.
 
In April 2010, the Company signed an agreement with the U.S. Department of Energy for a grant of approximately $84 million in matching funds on total anticipated spending of approximately $168 million related to the accelerated deployment of smart grid technology in Michigan through 2012. The smart grid technology includes


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the establishment of an advanced metering infrastructure and other technologies that address improved electric distribution service. See Note 2 of the Notes to Consolidated Financial Statements.
 
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.
 
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, the 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. To comply with these requirements, Detroit Edison has spent approximately $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of over $230 million in 2011 and up to $2.1 billion of additional capital expenditures through 2020 based on current regulations. 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 operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.
 
On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison’s fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA’s motion for preliminary injunction was denied and the liability phase of the civil suit has been scheduled for trial in May 2011.
 
DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the civil action, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company 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 completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted in a delay in compliance dates. The decision also raised the


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possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA’s use of this provision in determining best technology available for reducing environmental impacts. The EPA continues to develop a revised rule, a draft of which is expected to be published in the first quarter of 2011, with a final rule scheduled for mid-2012. The EPA has also issued 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, 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.
 
Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.
 
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 published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either, to designate coal ash as a “Hazardous Waste” as defined by RCRA or to regulate coal ash as non- hazardous waste under RCRA. However, agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the 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 significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the impact of those expected rulemakings at this time.
 
Non-Utility
 
The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants.
 
The Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a Notice of Violation in June of 2007 alleging potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDNRE concerning visible emissions readings that resulted from the Company self reporting to MDNRE questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the impact of this investigation.
 
The Company is also in the process of settling historical air and water violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the impact of this settlement. The Company received two notices of violation from the Pennsylvania Department of Environmental Protection in 2010 alleging


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violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend approximately $0.7 million on the existing waste water treatment system to comply with existing water discharge requirements. The Company may spend an additional $13 million over the next few years to meet future regulatory requirements and gain other operational improvements/savings. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.
 
Global Climate Change
 
Climate regulation and/or legislation is being proposed and discussed within the U.S. Congress and the EPA. Despite passage of a greenhouse gas cap and trade bill by the U.S. House in June 2009, the Senate has been unable to pass a similar climate bill. A greenhouse gas cap and trade program is not expected to be included in energy or climate bills to be considered by the 112th Congress. Meanwhile, the EPA is beginning to implement regulatory actions under the Clean Air Act to address emission of greenhouse gases. The EPA regulation of greenhouse gases (GHGs) begins in 2011 requiring the best available control technology (BACT) for major sources or modifications to existing major sources that cause significant increases in GHG emissions. The impact of this rule is uncertain until BACT is better defined by the permitting agencies. 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, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. 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.
 
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:
 
  •  improving Electric and Gas Utility customer satisfaction;
 
  •  continuing to pursue regulatory stability and investment recovery for our utilities;
 
  •  managing the growth of our utility asset base;
 
  •  optimizing our cost structure across all business segments;
 
  •  managing cash, capital and liquidity to maintain or improve our financial strength; and
 
  •  investing in businesses that integrate our assets and leverage our skills and expertise.
 
We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.
 
RESULTS OF OPERATIONS
 
The following sections provide a detailed discussion of the operating performance and future outlook of our segments.
 


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    2010     2009     2008  
    (In millions)  
 
Net Income Attributable to DTE Energy by Segment:
                       
Electric Utility
  $ 441     $ 376     $ 331  
Gas Utility
    127       80       85  
Gas Storage and Pipelines
    51       49       38  
Unconventional Gas Production(1)
    (11 )     (9 )     84  
Power and Industrial Projects
    85       31       40  
Energy Trading
    6       75       42  
Corporate & Other
    (69 )     (70 )     (94 )
Discontinued Operations
                20  
                         
Net Income Attributable to DTE Energy Company
  $ 630     $ 532     $ 546  
                         
 
 
(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 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:
 
                         
    2010     2009     2008  
    (In millions)  
 
Operating Revenues
  $ 4,993     $ 4,714     $ 4,874  
Fuel and Purchased Power
    1,580       1,491       1,778  
                         
Gross Margin
    3,413       3,223       3,096  
Operation and Maintenance
    1,305       1,277       1,322  
Depreciation and Amortization
    849       844       743  
Taxes Other Than Income
    237       205       232  
Asset (Gains) Losses, Reserves and Impairments, Net
    (6 )     (2 )     (1 )
                         
Operating Income
    1,028       899       800  
Other (Income) and Deductions
    317       295       283  
Income Tax Provision
    270       228       186  
                         
Net Income Attributable to DTE Energy Company
  $ 441     $ 376     $ 331  
                         
Operating Income as a Percent of Operating Revenues
    21 %     19 %     16 %
 
Gross margin increased $190 million in 2010 and increased $127 million in 2009. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:
 
                 
    2010     2009  
    (In millions)  
 
Weather, net of RDM
  $ 84     $ (66 )
Energy optimization and renewable surcharge/regulatory offset
    (10 )     54  
Securitization bond and tax surcharge rate increase
    40       62  
2010 rate order, surcharges and other
    76       77  
                 
Increase in gross margin
  $ 190     $ 127  
                 
 

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    2010     2009     2008  
    (In thousands of MWh)  
 
Electric Sales
                       
Residential
    15,726       14,625       15,492  
Commercial
    16,570       18,200       18,920  
Industrial
    10,195       9,922       13,086  
Other
    3,210       3,229       3,218  
                         
      45,701       45,976       50,716  
Interconnection sales(1)
    4,876       5,156       3,583  
                         
Total Electric Sales
    50,577       51,132       54,299  
                         
Electric Deliveries
                       
Retail and Wholesale
    45,701       45,976       50,716  
Electric Customer Choice, including self generators(2)
    5,005       1,477       1,457  
                         
Total Electric Sales and Deliveries
    50,706       47,453       52,173  
                         
 
 
(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.
 
                                                 
    2010     2009     2008  
    (In thousands of MWh)  
 
Power Generated and Purchased
                                               
Power Plant Generation
                                               
Fossil
    39,433       73 %     40,595       74 %     41,254       71 %
Nuclear
    7,738       14       7,406       14       9,613       17  
                                                 
      47,171       87       48,001       88       50,867       88  
Purchased Power
    6,638       13       6,495       12       6,877       12  
                                                 
System Output
    53,809       100 %     54,496       100 %     57,744       100 %
Less Line Loss and Internal Use
    (3,232 )             (3,364 )             (3,445 )        
                                                 
Net System Output
    50,577               51,132               54,299          
                                                 
Average Unit Cost ($/MWh)
                                               
Generation(1)
  $ 18.94             $ 18.20             $ 17.93          
                                                 
Purchased Power
  $ 42.38             $ 37.74             $ 69.50          
                                                 
Overall Average Unit Cost
  $ 21.83             $ 20.53             $ 24.07          
                                                 
 
 
(1) Represents fuel costs associated with power plants.
 
Operation and maintenance expense increased $28 million in 2010 and decreased $45 million in 2009. The increase in 2010 is primarily due to higher restoration and line clearance expenses of $40 million, higher energy optimization and renewable energy expenses of $18 million, higher legal expenses of $15 million, partially offset by reduced uncollectible expenses of $20 million, lower generation expenses of $18 million and lower employee benefit-related expenses of $6 million. 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 restoration and line clearance 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.

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Depreciation and amortization expense increased $5 million in 2010 and $101 million in 2009 due primarily to a higher depreciable base and increased amortization of regulatory assets.
 
Taxes other than income were higher by $32 million in 2010 due primarily to a $30 million reduction in property tax expense in 2009 due to refunds received in settlement of appeals of assessments for prior years.
 
Outlook  — We continue to move forward in our efforts to improve the operating performance and cash flow of Detroit Edison. The 2010 MPSC order provided for an uncollectible expense tracking mechanism which financially assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions, weather and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, we face additional challenges, such as higher levels of capital spending, volatility in prices for coal and other commodities, increased transportation costs, investment returns and changes in discount rate assumptions in benefit plans and health care costs, lower levels of wholesale sales due to contract expirations, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue our continuous improvement efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.
 
GAS UTILITY
 
Our Gas Utility segment consists of MichCon and Citizens.
 
Gas Utility results are discussed below:
 
                         
    2010     2009     2008  
    (In millions)  
 
Operating Revenues
  $ 1,648     $ 1,788     $ 2,152  
Cost of Gas
    870       1,057       1,378  
                         
Gross Margin
    778       731       774  
Operation and Maintenance
    378       415       464  
Depreciation and Amortization
    92       107       102  
Taxes Other Than Income
    55       49       48  
Asset (Gains) and Losses, Net
          (18 )     (26 )
                         
Operating Income
    253       178       186  
Other (Income) and Deductions
    59       59       60  
Income Tax Provision
    67       39       41  
                         
Net Income Attributable to DTE Energy Company
  $ 127     $ 80     $ 85  
                         
Operating Income as a Percent of Operating Revenues
    15 %     10 %     9 %
 
Gross margin increased $47 million in 2010 and decreased $43 million in 2009. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement


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of Operations. The following table details changes in various gross margin components relative to the comparable prior period:
 
                 
    2010     2009  
    (In millions)  
 
2010 self-implementation and rate order
  $ 125     $  
Lost and stolen gas
    13       (15 )
Midstream transportation and storage revenues
    (20 )     22  
Uncollectible tracking mechanism
    (43 )     (28 )
Lower sales volumes
          (13 )
Weather
    (23 )     (4 )
Other
    (5 )     (5 )
                 
Increase (decrease) in gross margin
  $ 47     $ (43 )
                 
 
                         
Gas Markets (in Bcf)
                       
Gas sales
    118       137       148  
End user transportation
    140       124       123  
                         
      258       261       271  
Intermediate transportation
    391       463       438  
                         
      649       724       709  
                         
 
Operation and maintenance expense decreased $37 million in 2010 and $49 million in 2009. The decrease in 2010 is primarily due to reduced uncollectible expenses of $35 million and the deferral of $32 million of previously expensed CTA restructuring expenses, partially offset by higher maintenance expenses of $11 million, increased energy optimization expenses of $9 million, higher employee benefit-related expenses of $3 million and expense of $3 million for contributions to the Low Income Energy Efficiency Fund. 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. See Note 12 of Notes to Consolidated Financial Statements in Item 8 of this report.
 
Depreciation and amortization expense decreased $15 million in 2010 due to the March 2010 MPSC order that reduced MichCon’s depreciation rates effective April 1, 2010.
 
Asset (gains) losses, net decreased $18 million due to 2009 gains on the sale of base gas and the sale of certain gathering and processing assets.
 
Outlook — We continue to move forward in our efforts to improve the operating performance and cash flow of Gas Utility. Unfavorable economic trends have resulted in a decrease in the number of customers in our service territory, increased customer conservation and continued high levels of theft and uncollectible accounts receivable. The MPSC has provided for an uncollectible expense tracking mechanism which assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility in the future. 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, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.


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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:
 
                         
    2010     2009     2008  
    (In millions)  
 
Operating Revenues
  $ 83     $ 82     $ 71  
Operation and Maintenance
    14       15       12  
Depreciation and Amortization
    5       5       5  
Taxes Other Than Income
    2       2       3  
Asset (Gains) and Losses, Net
                1  
                         
Operating Income
    62       60       50  
Other (Income) and Deductions
    (25 )     (23 )     (12 )
Income Tax Provision
    32       33       24  
                         
Net Income
    55       50       38  
Noncontrolling interest
    4       1        
                         
Net Income Attributable to DTE Energy
  $ 51     $ 49     $ 38  
                         
 
Net income attributable to DTE Energy increased $2 million and $11 million in 2010 and 2009, respectively. The 2010 increase was driven by higher gas storage revenues and lower project development costs. 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, in 2009 we had higher equity earnings from our investments in the Vector and Millennium Pipelines, reflecting a first full year of operations for Millennium.
 
Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities.
 
UNCONVENTIONAL GAS PRODUCTION
 
Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production within the Barnett shale in northern Texas. In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. We recognized a gain of $128 million ($80 million after-tax) on the sale in 2008.
 
Unconventional Gas Production results are discussed below:
 
                         
    2010     2009     2008  
    (In millions)  
 
Operating Revenues
  $ 32     $ 31     $ 48  
Operation and Maintenance
    16       15       22  
Depreciation, Depletion and Amortization
    15       16       12  
Taxes Other Than Income
    2       1       1  
Asset (Gains) and Losses, Net
    10       6       (120 )
                         
Operating Income (Loss)
    (11 )     (7 )     133  
Other (Income) and Deductions
    6       6       2  
Income Tax Provision (Benefit)
    (6 )     (4 )     47  
                         
Net Income (Loss) Attributable to DTE Energy Company
  $ (11 )   $ (9 )   $ 84  
                         


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Operating revenues increased $1 million in 2010 as a result of higher commodity prices, and an increase in oil production. The 2009 decrease of $17 million was due to lower commodity prices realized for physical sales as well as a reduction in volumes hedged.
 
Operation and maintenance expense increased $1 million in 2010 due to more wells on line and increased water handling cost. The decrease of $7 million in 2009 was due to operational efficiencies and lower costs for goods and services due to economic conditions.
 
Asset (gains) and losses, net increased $4 million in 2010 and decreased $126 million in 2009. The increase in 2010 was due to impairment of unproved leasehold positions that the Company does not intend to drill prior to expiration. The 2009 decrease 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 did not intend to drill at then current commodity prices.
 
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 when conditions are appropriate. Our strategy for 2011 is to maintain our focus on reducing operating expenses and optimizing production volume. Given the current outlook of low natural gas prices, drilling efforts will continue to target liquids rich gas and oil production. During 2011, we expect total capital investment of $25 million to drill approximately 20 new wells and continue to acquire select acreage and achieve production of approximately 6 Bcfe of natural gas, compared with 5 Bcfe in 2010.
 
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:
 
                         
    2010     2009     2008  
    (In millions)  
 
Operating Revenues
  $ 1,144     $ 661     $ 987  
Operation and Maintenance
    978       593       899  
Depreciation and Amortization
    60       40       34  
Taxes other than Income
    14       9       12  
Other Asset (Gains) and Losses, Reserves and Impairments, Net
    (14 )     (6 )     6  
                         
Operating Income
    106       25       36  
Other (Income) and Deductions
    13       (1 )     (20 )
Income Taxes
                       
Provision
    36       5       18  
Production Tax Credits
    (33 )     (12 )     (7 )
                         
      3       (7 )     11  
                         
Net Income
    90       33       45  
Noncontrolling interest
    5       2       5  
                         
Net Income Attributable to DTE Energy Company
  $ 85     $ 31     $ 40  
                         
 
VIEs — As discussed in Notes 1 and 3 of Notes to the Consolidated Financial Statements, effective January 1, 2010, we adopted the provisions of ASU 2009-17, Amendments to FASB Interpretation 46(R). ASU 2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, began consolidating five entities. Since these entities were previously accounted for under the equity method, the VIE consolidation had no impact on Net Income Attributable to DTE Energy. As a


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result of the consolidation of these VIEs, Operating Revenues and Operations and Maintenance expense increased $174 million and $122 million, respectively, in 2010.
 
Operating revenues increased $309 million, net of VIE adjustments, in 2010 and decreased $326 million in 2009. The 2010 increase is attributed primarily to $172 million of higher coke sales and a $156 million increase in on-site services, partially offset by a $18 million decrease in coal trading and transportation services. 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.
 
Operation and maintenance expense increased $262 million, net of VIE adjustments, in 2010 and decreased $306 million in 2009. The increase is due primarily to $118 million of higher coke production and a $154 million increase in on-site services, partially offset by $10 million of lower coal trading and transportation services. 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.
 
Asset (Gains) Losses were higher by $8 million in 2010 due primarily to the sale of DTE Rail Services and an increase in installment gains from the sale of a coke battery.
 
Other (income) and deductions were lower by $14 million in 2010 and lower by $19 million in 2009. The decreases in both years were due primarily to lower equity earnings in various projects and higher intercompany interest associated with project investment.
 
Outlook — We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2011. Beginning in 2011, substantially all of the metallurgical coke is under long-term contracts. The tax credits associated with our steel industry fuels facilities expired at December 31, 2010 that will result in lower tax credits of approximately $29 million in 2011. We supply on-site energy services to the domestic automotive manufacturers who have also experienced stabilized demand for automobiles. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts.
 
In late 2009, we began operating reduced emission fuel facilities located at Detroit Edison owned coal-fired power plants. The facilities reduce Nitrogen Oxide (NO) and Mercury (Hg) emissions and qualify for production tax credits when the fuel is sold to an unrelated party through 2019. We continue to optimize these facilities by seeking investors for facilities operating at Detroit Edison sites and intend to relocate other facilities to alternative sites which may provide increased production and emission reduction opportunities in 2011 and future years. In January 2011, the Company entered into an agreement to sell a membership interest in one of these reduced emission fuel facilities that is located at a Detroit Edison site.
 
Environmental and economic trends are creating growth opportunities for renewable power. The increasing number of states with renewable portfolio standards and energy efficiency mandates provides investment opportunity in waste-wood power generation. In addition to the three facilities in operation, we will convert and place into service two additional facilities in 2011 and 2013. We will continue to look for additional investment opportunities for waste-wood renewable power generation and other energy projects at favorable prices.
 
Effective January 1, 2011, our existing long-term rail transportation contract, at rates significantly below the current market, expired and we anticipate a decrease in transportation-related revenue of approximately $130 million as a result. The decrease in revenue will be mostly offset by lower variable costs incurred to provide the transportation.
 
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.
 
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


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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.
 
Energy Trading results are discussed below:
 
                         
    2010     2009     2008  
    (In millions)  
 
Operating Revenues
  $ 875     $ 804     $ 1,388  
Fuel, Purchased Power and Gas
    786       603       1,235  
                         
Gross Margin
    89       201       153  
Operation and Maintenance
    59       71       68  
Depreciation and Amortization
    5       5       5  
Taxes Other Than Income
    2       3       2  
                         
Operating Income
    23       122       78  
Other (Income) and Deductions
    12       10       5  
Income Tax Provision (Benefit)
    5       37       31  
                         
Net Income Attributable to DTE Energy Company
  $ 6     $ 75     $ 42  
                         
 
Gross margin decreased $112 million in 2010 and increased $48 million in 2009. The overall decrease in gross margin in 2010 was the result of lower economic performance, lower commodity prices, lower volatility in the markets we participate in and lower risk positions relative to 2009, coupled with the absence of prior year timing-related gains. We experienced timing-related earnings volatility based on market movement related to derivative contracts.
 
The decrease in 2010 represents a $78 million decrease in realized margins and $34 million decrease in unrealized margins. The $78 million decrease in realized margins is due to $108 million of unfavorable results, primarily in our power and gas trading and gas full requirements strategies, offset by $30 million of favorable results, primarily in our power full requirements and power origination strategies. The $34 million decrease in unrealized margins is due to $56 million of unfavorable results, primarily in our power trading strategy and the absence of prior year timing-related gains related to our gas transportation strategy. These decreases were offset by $22 million of favorable results, primarily due to timing-related gains in our gas full requirements strategy.
 
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 gas transportation strategies. The $21 million decrease in unrealized margins consisted of unfavorable results of $58 million from our gas trading and gas storage strategies, partially offset by increases of $29 million primarily in our power trading strategy and timing-related improvements of $8 million in our oil strategies.
 
Operation and maintenance expense decreased $12 million in 2010 and increased $3 million in 2009. The 2010 decrease was primarily due to lower incentive costs. The 2009 increase was due to higher payroll and incentive costs and commissions, partially offset by lower contractor expense and allocated corporate costs.
 
Income tax provision decreased $32 million in 2010. This decrease is due to lower pretax income, partially offset by $10 million of favorable tax-related adjustments in 2009 resulting from the settlement of federal income tax audits. Income taxes were higher by $6 million in 2009 due to higher pretax income, partially offset by the $10 million of favorable tax-related adjustments.
 
Outlook — In the near term, we expect market conditions to remain challenging and the profitability of this segment may be impacted by the volatility or lack thereof in commodity prices in the markets we participate in and the uncertainty of impacts associated with financial reform, regulatory changes and changes in operating rules of regional transmission organizations.


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The Energy Trading 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 natural gas, power and ancillary services to various utilities which may include the management of associated storage and transportation contracts on the customers’ behalf. Significant portions of the Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives, whereas natural 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.
 
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.
 
The 2010 net loss of $69 million was an improvement of $1 million from the 2009 net loss of $70 million. The net $1 million improvement was a result of the 2009 donation to the DTE Energy Foundation of $10 million and lower impairments of investments of $3 million, partially offset by higher state and local taxes of $3 million, higher tax related interest of $5 million, increased financing costs of $5 million. The 2010 donation to the DTE Energy Foundation of $14 million was made by Detroit Edison and MichCon.
 
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.
 
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.
 
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 2011, we expect that cash from operations will be $1.9 billion due to lower working capital requirements. We anticipate base level capital investments and expenditures for existing businesses in 2011 of up to $1.4 billion. The capital needs of our utilities will increase due primarily to environmental expenditures. 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


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existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.
 
                         
    2010     2009     2008  
    (In millions)  
 
Cash and Cash Equivalents
                       
Cash Flow From (Used For)
                       
Operating activities:
                       
Net income
  $ 639     $ 535     $ 553  
Depreciation, depletion and amortization
    1,027       1,020       899  
Deferred income taxes
    457       205       348  
Gain on sale of non-utility business
                (128 )
Gain on sale of synfuel and other assets, net and synfuel impairment
    (5 )     (10 )     (35 )
Working capital and other
    (293 )     69       (78 )
                         
      1,825       1,819       1,559  
                         
Investing activities:
                       
Plant and equipment expenditures — utility
    (1,011 )     (960 )     (1,183 )
Plant and equipment expenditures — non-utility
    (88 )     (75 )     (190 )
Proceeds from sale of non-utility business
                253  
Proceeds (refunds) from sale of synfuels and other assets
    56       83       (278 )
Restricted cash and other investments
    (183 )     (112 )     (125 )
                         
      (1,226 )     (1,064 )     (1,523 )
                         
Financing activities:
                       
Issuance of long-term debt
    614       427       1,310  
Redemption of long-term debt
    (663 )     (486 )     (446 )
Repurchase of long-term debt
                (238 )
Short-term borrowings, net
    (177 )     (417 )     (340 )
Issuance of common stock
    36       35        
Repurchase of common stock
                (16 )
Dividends on common stock and other
    (396 )     (348 )     (354 )
                         
      (586 )     (789 )     (84 )
                         
Net Increase (Decrease) in Cash and Cash Equivalents
  $ 13     $ (34 )   $ (48 )
                         
 
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 2010 was consistent with the comparable 2009 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 income taxes and gains on sales of assets), offset by higher working capital requirements.
 
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 income taxes and gains on sales of assets).
 
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


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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 $1.2 billion in 2010, compared with net cash used for investing activities of $1.1 billion in 2009. The change was primarily driven by increased capital expenditures by our utility and non-utility businesses.
 
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.
 
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.
 
Net cash used for financing activities was $586 million in 2010, compared to net cash used for financing activities of approximately $789 million for the same period in 2009. The change was primarily attributable to decreased payments for short-term borrowings. Increases in issuances of long-term debt were offset by increased long-term debt redemptions.
 
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.
 
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 may be impacted by the delayed collection of underrecoveries of our various recovery and tracking mechanisms as a result of timing 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.
 
We have approximately $900 million in long-term debt maturing in the next twelve months. DTE Energy has $600 million of unsecured debt maturing in June 2011 which is expected to be funded through a combination of internally generated funds and short- term debt. Substantially all of the remaining debt maturities relate to Securitization and other Detroit Edison issues. The repayment of the principal amount of the Securitization debt is


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funded through a surcharge payable by Detroit Edison’s electric customers. The repayment of the other Detroit Edison debt is expected to be refinanced with long-term debt.
 
In August 2010, DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon, entered into amended and restated two-year $1 billion unsecured revolving credit agreements and new three-year $800 million unsecured revolving credit agreements with a syndicate of 23 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.25% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. DTE Energy has approximately $1.7 billion of available liquidity at December 31, 2010.
 
In March 2010, the PPACA and the HCERA were enacted into law (collectively, the “Act”). The Act is a comprehensive health care reform bill. A provision of the PPACA repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012. We have initiated changes in benefit design and delivery and are continuing to evaluate alternatives to minimize the impact of the legislation. We contributed $200 million to our pension plans during the year ended December 31, 2010, including a DTE Energy stock contribution of $100 million in March 2010. We contributed $160 million to our postretirement medical and life insurance benefit plans during the year ended December 31, 2010, including a transfer of $25 million from the MichCon Grantor Trust. In January 2011, we contributed $200 million to our pension plans. Also, we contributed $81 million to our postretirement medical and life insurance plans in January 2011, and we expect to contribute up to an additional $90 million throughout the remainder of 2011.
 
In July 2010, a federal financial reform act was signed into law. The legislation reshapes financial regulation and is intended to address specific issues that contributed to the financial crisis. Most major areas of the legislation will be dependent upon regulatory interpretation, rulemaking and implementation. We do not expect any material effect on our operations and financial position.
 
The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 provided for a special allowance for bonus depreciation in 2011 and 2012. Bonus depreciation is accelerated depreciation on certain types of business equipment that allows a tax deduction of either 50% or 100% of the cost of qualifying property in the year the asset is placed in service. DTE Energy expects to generate approximately $100 million to $200 million of cash in 2011-2012 from bonus depreciation deductions, a significant portion of which is expected to result from Detroit Edison property, plant and equipment expenditures during the qualifying period. The cash benefit is an acceleration of tax deductions that the Company would otherwise have received over 20 years.
 
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, 16, 18, and 21 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


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Contractual Obligations
 
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2010:
 
                                         
                            2016
 
    Total     2011     2012-2013     2014-2015     and Beyond  
    (In millions)  
 
Long-term debt:
                                       
Mortgage bonds, notes and other
  $ 6,888     $ 765     $ 691     $ 1,036     $ 4,396  
Securitization bonds
    793       150       341       302        
Trust preferred-linked securities
    289                         289  
Capital lease obligations
    62       12       18       18       14  
Interest
    5,547       457       814       649       3,627  
Operating leases
    211       39       58       40       74  
Electric, gas, fuel, transportation and storage purchase obligations(1)
    5,921       2,175       1,670       744       1,332  
Other long-term obligations(2)(3)(4)
    243       49       44       31       119  
                                         
Total obligations
  $ 19,954     $ 3,647     $ 3,636     $ 2,820     $ 9,851  
                                         
 
 
(1) Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.
 
(2) Includes liabilities for unrecognized tax benefits of $28 million.
 
(3) Excludes other long-term liabilities of $184 million not directly derived from contracts or other agreements.
 
(4) At December 31, 2010, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Capital Resources and Liquidity and Critical Accounting Estimates sections 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. The Company’s credit ratings affect our cost of capital and other terms of financing as well as our ability to access the credit and commercial paper markets. 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 senior unsecured debt 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 senior unsecured debt 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


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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 January 2010, Standard & Poor’s Rating Group (Standard & Poor’s) revised the outlook on DTE Energy and its subsidiaries to stable from negative, and raised the short-term corporate credit and commercial paper ratings for DTE Energy, Detroit Edison and MichCon to ‘A-2’ from ‘A-3’. The revision was primarily due to the diminished possibility of a downgrade in light of the Company’s decreasing regulatory risk. 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. In June 2010, Standard & Poor’s revised the outlook on DTE Energy and its subsidiaries to positive from stable. The outlook revision reflected the Company’s decreasing regulatory risk. In December 2010, Standard and Poor’s upgraded the corporate credit rating of DTE Energy and its utility subsidiaries to ‘BBB+’ from ‘BBB’ to reflect the company’s decreasing regulatory risk and improved financial measures. At the same time, Standard and Poor’s raised the rating on Detroit Edison’s senior secured debt to ‘A’ from ‘A-’ and raised the rating on MichCon’s senior secured debt to ‘A’ from ‘BBB+’. In January 2011, Fitch Ratings revised the rating outlook for Detroit Edison to positive from stable due to improvement in its credit protection measures as a result of supportive regulatory policies in Michigan.
 
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.
 
In March 2010, the PPACA and the HCERA were enacted into law (collectively, the “Act”). A provision of the PPACA repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012. This change in tax law required a remeasurement of the deferred tax asset related to the Other Postretirement Benefit Obligation (OPEB) and the deferred tax liability related to the OPEB Regulatory Asset. Income tax accounting rules require the impact of a change in tax law be recognized in continuing operations in the Consolidated Statements of Operations in the period that the tax law change is enacted. However, regulated businesses may defer changes in tax law if allowed by regulators. The MPSC’s historical practice has been to recognize both the expense and working capital impacts for OPEB costs. In addition, the current and deferred tax effects related to OPEB costs have been recognized consistently. The effects of the subsidy have been reflected through lower tax expense included in rates. We believe we have reasonable assurance that the impacts related to the enactment of the Act are recoverable through rates in future periods. Therefore, the amounts related to Detroit Edison of $18 million and MichCon of $4 million have been deferred as Regulatory Assets.
 
See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this Report.


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Derivatives and Hedging Activities
 
Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. 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 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. Management makes certain assumptions it believes that market participants would use in pricing assets and liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and our counterparties is incorporated in the valuation of the assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 2010 and 2009. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
 
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 2010, our allowance for doubtful accounts decreased significantly from the 2009 balance. 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. Detroit Edison filed for the suspension of the tracking mechanism effective with the order in its pending rate case.
 
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


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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, 2010 and determined that except for the Coal Services reporting unit, the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. The $4 million of goodwill attributable to the Coal Services reporting unit was written off in the fourth quarter of 2010 in connection with the sale of rail services assets. We also compared the 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 an acquisition control premium (the price in excess of a stock’s market price that investors typically pay to gain control of an entity). The results of the test and key estimates that were incorporated are as follows.
 
As of October 1, 2010 Valuation Date
 
                                     
          Fair Value
    Discount
    Terminal
     
Reporting Unit   Goodwill     Reduction %(a)     Rate     Multiple(b)     Valuation Methodology(c)
    ($ in millions)                        
 
Electric Utility
  $ 1,206       26 %     7 %     8.0 x   DCF, assuming stock sale
Gas Utility
    759       7 %     7 %     9.5 x   DCF, assuming stock sale
Energy Services
    28       66 %     13 %     9.0 x   DCF, assuming asset sale(d)
Coal Services
    4 (e)     n/a       12 %     8.5 x   DCF, assuming asset sale
Gas Storage and Pipelines
    8       66 %     10 %     8.0 x   DCF, assuming asset sale
Energy Trading
    17       74 %     15 %     n/a     Blended DCF, economic value of trading portfolio
Unconventional Gas Production
    2       62 %     13 %     n/a     Blended DCF, transaction multiples
                                     
    $ 2,024                              
                                     
 
 
(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 2011-2015 projected cash flows plus a calculated terminal value.
 
(d) Asset sales were assumed except for Energy Services’ reduced emissions fuel projects, which assumed stock sales.
 
(e) Goodwill attributable to Coal Services was written off in connection with the sale of rail services assets. Refer to Note 10 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
The Gas Utility reporting unit passed Step 1 of the impairment test by a 7% margin. A substantive decrease 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.


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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 11 of Notes to Consolidated Financial Statements in Item 8 of this Report.
 
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 $112 million in 2010, $58 million in 2009, and $24 million in 2008. Postretirement benefits costs for all plans were $164 million in 2010, $205 million in 2009 and $142 million in 2008. Pension and postretirement benefits costs for 2010 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 assumptions, 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 2011 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment management of 47% in equity markets, 25% in fixed income markets, and 28% 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 are lowering our long-term rate of return assumption for our pension plans to 8.50% for 2011. Our long-term rate of return assumption for our postretirement health and life plans will remain at 8.75% for 2011. We believe these two rates are reasonable assumptions for the long-term rate of return on our plan assets for 2011 given our investment strategy. 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 2010 contributed to our investment performance resulting in unrecognized net gains. As of December 31, 2010, we had $242 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


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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 pension plan and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis decreased to 5.5% at December 31, 2010 from 5.9% at December 31, 2009. We estimate that our 2011 total pension costs will approximate $167 million compared to $112 million in 2010 primarily due to a lower discount rate, partially offset by better than expected asset returns in 2010 and 2011 contributions. Our 2011 postretirement benefit costs will approximate $137 million compared to $164 million in 2010 primarily due to changing our strategy for providing post-65 prescription drug benefits to retirees, better than expected asset returns in 2010 and favorable retiree medical utilization. These positive impacts were partially offset by a lower discount rate and updated assumed long-term retiree medical inflation. Our health care trend rate assumes 7% for 2011 through 2015, 6.5% in 2016, 6% in 2017, 5.5% in 2018 and 5% in 2019 and beyond. 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 January 1, 2009. 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 2010 pension costs by approximately $30 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 2010 pension costs by approximately $10 million. Lowering the health care cost trend assumptions by one percentage point would have decreased our postretirement benefit service and interest costs for 2010 by approximately $25 million.
 
The value of our pension and postretirement benefit plan assets was $3.9 billion at December 31, 2010 and $3.4 billion at December 31, 2009. At December 31, 2010 our pension plans were underfunded by $872 million and our other postretirement benefit plans were underfunded by $1.3 billion. The 2010 and 2009 funding levels were generally similar due to positive investment performance returns and plan sponsor contributions in 2010 and 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 in each of 2010 and 2009. Also, we contributed $200 million to our pension plans in January 2011. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making contributions to our pension plans of up to $1.2 billion over the next five years. We made postretirement benefit plan contributions of $160 million and $205 million in 2010 and 2009, 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 contributed $81 million to our postretirement plans in January 2011 and expect to make up to an additional $90 million contribution to our postretirement plans in 2011 and, subject to MPSC funding requirements, up to $850 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.


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Insured and Uninsured Risks
 
Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage- $10 million, general liability- $7 million, workers’ compensation- $9 million, and auto liability-$7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2010, this IBNR liability was approximately $39 million.
 
Accounting for Tax Obligations
 
We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. 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, 2010 and December 31, 2009 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 currency exchange contracts. Items we do not generally account for as derivatives include natural gas inventory, power transmission, pipeline transportation and certain storage assets. See Notes 4 and 5 of the Notes to Consolidated Financial Statements.
 
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).


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The Company has established a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value hierarchy, see Note 4 of the Notes to Consolidated Financial Statements.
 
The following tables provide details on changes in our MTM net asset (or liability) position during 2010:
 
         
    Total  
    (In millions)  
 
MTM at December 31, 2009
  $ (93 )
         
Reclassify to realized upon settlement
    (3 )
Changes in fair value recorded to income
    123  
         
Amounts recorded to unrealized income
    120  
Changes in fair value recorded in regulatory liabilities
    6  
Amounts recorded in other comprehensive income pre-tax
    1  
Change in collateral held for others
    (42 )
Option premiums paid (received) and other
    (36 )
         
MTM at December 31, 2010
  $ (44 )
         
 
The table below shows the maturity of our MTM positions:
 
                                         
                      2014
       
                      and
    Total Fair
 
Source of Fair Value   2011     2012     2013     Beyond     Value  
    (In millions)  
 
Level 1
  $ 9     $ (23 )   $ 11     $ 10     $ 7  
Level 2
    (68 )     (54 )     (32 )           (154 )
Level 3
    29       33       (2 )     (1 )     59  
                                         
Total MTM before netting adjustments
  $ (30 )   $ (44 )   $ (23 )   $ 9     $ (88 )
                                         
Collateral adjustments
                                  $ 44  
                                         
Total MTM at December 31, 2010
                                  $ (44 )
                                         
 
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 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 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.


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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 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 currency 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.
 
Other
 
The Company has tracking mechanisms to mitigate a significant amount of losses related to uncollectible accounts receivable at Detroit Edison and MichCon. These mechanisms are subject to the jurisdiction of the MPSC and are periodically reviewed. See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
 
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 internal 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, 2010:
 
                         
    Credit Exposure
             
    Before Cash
    Cash
    Net Credit
 
    Collateral     Collateral     Exposure  
    (In millions)  
 
Investment Grade(1)
                       
A− and Greater
  $ 163     $ (10 )   $ 153  
BBB+ and BBB
    199             199  
BBB−
    54             54  
                         
Total Investment Grade
    416       (10 )     406  
Non-investment grade(2)
    2             2  
Internally Rated — investment grade(3)
    147             147  
Internally Rated — non-investment grade(4)
    12             12  
                         
Total
  $ 577     $ (10 )   $ 567  
                         
 
 
(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


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largest counterparty exposures combined for this category represented approximately 36 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 18 percent of the total gross credit exposure.
 
(4) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately two percent of the total gross credit exposure.
 
Interest Rate Risk
 
We are subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of December 31, 2010, we had a floating rate debt-to-total debt ratio of approximately two percent (excluding securitized debt).
 
Foreign Currency Exchange Risk
 
We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency exchange fluctuations, we have entered into a series of exchange forward contracts through January 2013. Additionally, we may enter into fair value foreign currency exchange hedges to mitigate changes in the value of contracts or loans.
 
Summary of Sensitivity Analysis
 
We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign currency exchange forward contracts. The commodity contracts and foreign currency exchange risk listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2010 and 2009 by a hypothetical 10% and calculating the resulting change in the fair values.
 
The results of the sensitivity analysis calculations as of December 31, 2010 and 2009:
 
                                     
    Assuming a
    Assuming a
     
    10% Increase in Rates     10% Decrease in Rates      
    As of December 31,     As of December 31,      
Activity   2010     2009     2010     2009     Change in the Fair Value of
    (In millions)      
 
Coal Contracts
  $ 1     $     $ (1 )   $     Commodity contracts
Gas Contracts
  $ (11 )   $ (2 )   $ 10     $ 1     Commodity contracts
Oil Contracts
  $     $ 1     $     $ (1 )   Commodity contracts
Power Contracts
  $ (5 )   $ (3 )   $ 5     $ 2     Commodity contracts
Interest Rate Risk
  $ (291 )   $ (290 )   $ 313     $ 313     Long-term debt
Foreign Currency Exchange Risk
  $ 6     $ 2     $ 7     $ (2 )   Forward contracts
Discount Rates
  $     $     $     $     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
 
    60  
Consolidated Financial Statements
       
    61  
    63  
    64  
    66  
    67  
    68  
    69  
    69  
    72  
    76  
    77  
    84  
    89  
    89  
    90  
    91  
    92  
    93  
    94  
    101  
    104  
    104  
    106  
    108  
    108  
    109  
    110  
    115  
    128  
    131  
    132  
    134  
Financial Statement Schedule
       
    146  


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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 (CEO) and Chief Financial Officer (CFO), 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, 2010, which is the end of the period covered by this report. Based on this evaluation, the Company’s CEO and CFO have concluded that such disclosure 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 (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, 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, 2010. 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, 2010, 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, 2010 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, 2010 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, 2010 and 2009, and the results of their operations and their cash flows for the years 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 years ended December 31, 2010 and 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, 2010, 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 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 audits 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 audits 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide 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 18, 2011


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of DTE Energy Company:
 
We have audited the consolidated statements of operations, cash flows, comprehensive income, and changes in equity of DTE Energy Company and subsidiaries (the “Company”) for the year ended December 31, 2008. Our audit also included the 2008 information in the financial statement schedule listed in the accompanying index. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit provides a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of DTE Energy Company and subsidiaries for the year ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2008 financial statement schedule, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, presents 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  
    2010     2009     2008  
    (In millions, except per share amounts)  
 
Operating Revenues
  $ 8,557     $ 8,014     $ 9,329  
                         
Operating Expenses
                       
Fuel, purchased power and gas
    3,190       3,118       4,306  
Operation and maintenance
    2,578       2,372       2,694  
Depreciation, depletion and amortization
    1,027       1,020       901  
Taxes other than income
    308       275       304  
Gain on sale of non-utility business
                (128 )
Other asset (gains) and losses, reserves and impairments, net
    (10 )     (20 )     (11 )
                         
      7,093       6,765       8,066  
                         
Operating Income
    1,464       1,249       1,263  
                         
Other (Income) and Deductions
                       
Interest expense
    549       545       503  
Interest income
    (12 )     (19 )     (19 )
Other income
    (78 )     (102 )     (104 )
Other expenses
    55       43       64  
                         
      514       467       444  
                         
Income Before Income Taxes
    950       782       819  
Income Tax Provision
    311       247       288  
                         
Income from Continuing Operations
    639       535       531  
Discontinued Operations Income, net of tax
                22  
                         
Net Income
    639       535       553  
Less: Net Income Attributable to Noncontrolling Interests From
                       
Continuing operations
    9       3       5  
Discontinued operations
                2  
                         
      9       3       7  
                         
Net Income Attributable to DTE Energy Company
  $ 630     $ 532     $ 546  
                         
Basic Earnings per Common Share
                       
Income from continuing operations
  $ 3.75     $ 3.24     $ 3.22  
Discontinued operations
                .12  
                         
Total
  $ 3.75     $ 3.24     $ 3.34  
                         
Diluted Earnings per Common Share
                       
Income from continuing operations
  $ 3.74     $ 3.24     $ 3.22  
Discontinued operations
                .12  
                         
Total
  $ 3.74     $ 3.24     $ 3.34  
                         
Weighted Average Common Shares Outstanding
                       
Basic
    168       164       163  
Diluted
    169       164       163  
Dividends Declared per Common Share
  $ 2.18     $ 2.12     $ 2.12  
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Financial Position
 
                 
    December 31  
    2010     2009  
    (In millions)  
 
ASSETS
Current Assets
               
Cash and cash equivalents
  $ 65     $ 52  
Restricted cash (Note 2)
    120       84  
Accounts receivable (less allowance for doubtful accounts of $196 and $262, respectively)
               
Customer
    1,393       1,438  
Other
    402       217  
Inventories
               
Fuel and gas
    460       309  
Materials and supplies
    202       200  
Deferred income taxes
    139       167  
Derivative assets
    131       209  
Other
    255       201  
                 
      3,167       2,877  
                 
Investments
               
Nuclear decommissioning trust funds
    939       817  
Other
    518       598  
                 
      1,457       1,415  
                 
Property
               
Property, plant and equipment
    21,574       20,588  
Less accumulated depreciation, depletion and amortization
    (8,582 )     (8,157 )
                 
      12,992       12,431  
                 
Other Assets
               
Goodwill
    2,020       2,024  
Regulatory assets
    4,058       4,110  
Securitized regulatory assets
    729       870  
Intangible assets
    67       54  
Notes receivable
    123       113  
Derivative assets
    77       116  
Other
    206       185  
                 
      7,280       7,472  
                 
Total Assets
  $ 24,896     $ 24,195  
                 
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Financial Position — (Continued)
 
                 
    December 31  
    2010     2009  
    (In millions, except shares)  
 
LIABILITIES AND EQUITY
Current Liabilities
               
Accounts payable
  $ 729     $ 723  
Accrued interest
    111       114  
Dividends payable
    95       88  
Short-term borrowings
    150       327  
Current portion long-term debt, including capital leases
    925       671  
Derivative liabilities
    142       220  
Other
    597       502  
                 
      2,749       2,645  
                 
Long-Term Debt (net of current portion)
               
Mortgage bonds, notes and other
    6,114       6,237  
Securitization bonds
    643       793  
Trust preferred-linked securities
    289       289  
Capital lease obligations
    43       51  
                 
      7,089       7,370  
                 
Other Liabilities
               
Deferred income taxes
    2,632       2,096  
Regulatory liabilities
    1,328       1,337  
Asset retirement obligations
    1,498       1,420  
Unamortized investment tax credit
    75       85  
Derivative liabilities
    110       198  
Liabilities from transportation and storage contracts
    83       96  
Accrued pension liability
    866       881  
Accrued postretirement liability
    1,275       1,287  
Nuclear decommissioning
    149       136  
Other
    275       328  
                 
      8,291       7,864  
                 
Commitments and Contingencies (Notes 12 and 20)
               
Equity
               
Common stock, without par value, 400,000,000 shares authorized, 169,428,406 and 165,400,045 shares issued and outstanding, respectively
    3,440       3,257  
Retained earnings
    3,431       3,168  
Accumulated other comprehensive loss
    (149 )     (147 )
                 
Total DTE Energy Company Shareholders’ Equity
    6,722       6,278  
Noncontrolling interests
    45       38  
                 
Total Equity
    6,767       6,316  
                 
Total Liabilities and Equity
  $ 24,896     $ 24,195  
                 
 
See Notes to Consolidated Financial Statements


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DTE Energy Company
 
Consolidated Statements of Cash Flows
 
                         
    Year Ended December 31  
    2010     2009     2008  
    (In millions)  
 
Operating Activities
                       
Net income
  $ 639     $ 535     $ 553  
Adjustments to reconcile net income to net cash from operating activities:
                       
Depreciation, depletion and amortization
    1,027       1,020       899  
Deferred income taxes
    457       205       348  
Gain on sale of non-utility business
                (128 )
Other asset (gains), losses and reserves, net
    (5 )     (10 )     (4 )
Gain on sale of interests in synfuel projects
                (31 )
Contributions from synfuel partners
                14  
Changes in assets and liabilities, exclusive of changes shown separately (Note 23)
    (293 )     69       (92 )
                         
Net cash from operating activities
    1,825       1,819       1,559  
                         
Investing Activities
                       
Plant and equipment expenditures — utility
    (1,011 )     (960 )     (1,183 )
Plant and equipment expenditures — non-utility
    (88 )     (75 )     (190 )
Proceeds from sale of interests in synfuel projects
                84  
Refunds to synfuel partners
                (387 )
Proceeds from sale of non-utility business
                253  
Proceeds from sale of other assets, net
    56       83       25  
Restricted cash for debt redemption
    (32 )     2       54  
Proceeds from sale of nuclear decommissioning trust fund assets
    377       295       232  
Investment in nuclear decommissioning trust funds
    (410 )     (315 )     (255 )
Consolidation of VIEs
    19              
Investment in Millennium Pipeline Project
    (49 )     (15 )     (31 )
Other investments
    (88 )     (79 )     (125 )
                         
Net cash used for investing activities
    (1,226 )     (1,064 )     (1,523 )
                         
Financing Activities
                       
Issuance of long-term debt
    614       427       1,310  
Redemption of long-term debt
    (663 )     (486 )     (446 )
Repurchase of long-term debt
                (238 )
Short-term borrowings, net
    (177 )     (417 )     (340 )
Issuance of common stock
    36       35        
Repurchase of common stock
                (16 )
Dividends on common stock
    (360 )     (348 )     (344 )
Other
    (36 )           (10 )
                         
Net cash used for financing activities
    (586 )     (789 )     (84 )
                         
Net Increase (Decrease) in Cash and Cash Equivalents
    13       (34 )     (48 )
Cash and Cash Equivalents Reclassified from Assets Held for Sale
                11  
Cash and Cash Equivalents at Beginning of Period
    52       86       123  
                         
Cash and Cash Equivalents at End of Period
  $ 65     $ 52     $ 86  
                         
 
See Notes to Consolidated Financial Statements


66


Table of Contents

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)  
 
Balance, December 31, 2007
    163,232     $ 3,176     $ 2,790     $ (113 )   $ 48     $ 5,901  
                                                 
Net income (loss)
                546             7       553  
Implementation of ASC 820, net of tax
                4                   4  
Implementation of ASC 715 measurement date provision, net of tax
                (9 )                 (9 )
Dividends declared on common stock
                (346 )                 (346 )
Repurchase and retirement of common stock
    (479 )     (16 )                       (16 )
Benefit obligations, net of tax
                      (22 )           (22 )
Foreign currency translation, net of tax
                      (2 )           (2 )
Net change in unrealized losses on derivatives, net of tax
                      6             6  
Net change in unrealized losses on investments, net of tax
                      (34 )           (34 )
Contributions from noncontrolling interests
                            14       14  
Stock-based compensation, distributions to noncontrolling interests and other
    267       15                   (26 )     (11 )
                                                 
Balance, December 31, 2008
    163,020       3,175       2,985       (165 )     43       6,038  
                                                 
Net income
                532             3       535  
Dividends declared on common stock
                (349 )                 (349 )
Issuance of common stock
    1,109       35                 &