DTE Energy 2011.12.31 10K
Table of Contents

 
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, 2011
¨
 
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
2011 Series I 6.5% Junior Subordinated Debentures due 2061
 
New York Stock Exchange
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, 2011, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $8.5 billion (based on the New York Stock Exchange closing price on such date). There were 169,403,378 shares of common stock outstanding at January 31, 2012.
Certain information in DTE Energy Company’s definitive Proxy Statement for its 2012 Annual Meeting of Common Shareholders to be held May 3, 2012, 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, 2011

TABLE OF CONTENTS

 
 
Page
 
 
 
 
 
 EX-12.49
 EX-21.7
 EX-23.25
 EX-31.71
 EX-31.72
 EX-32.71
 EX-32.72
 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
 
 
 
 
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.
 
 
 
 
Citizens
Citizens Fuel Gas Company, which distributes natural gas in Adrian, Michigan
 
 
 
 
Company
DTE Energy Company and any subsidiary companies
 
 
 
 
CTA
Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
 
 
 
 
Customer Choice
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.
 
 
 
 
MCIT
Michigan Corporate Income Tax
 
 
 
 
MDEQ
Michigan Department of Environmental Quality
 
 
 
 
MichCon
Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies
 
 
 
 
MISO
Midwest Independent System Operator is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.
 
 
 
 
MPSC
Michigan Public Service Commission
 
 
 
 
Non-utility
An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC.
 
 
 
 
NRC
United States Nuclear Regulatory Commission
 
 
 
 
Production tax credits
Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.

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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 using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.
 
 
 
 
BTU
Heat value (energy content) of fuel
 
 
 
 
dth/d
Decatherms per day
 
 
 
 
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. Words such as “anticipate,” “believe,” “expect,” “projected” and “goals” signify forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather 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:

impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;
the amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;
impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs;
economic conditions and population changes in our geographic area resulting in changes in demand, customer conservation, increased thefts of electricity and gas and high levels of uncollectible accounts receivable;
environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements;
health, safety, financial, environmental and regulatory risks associated with ownership and operation of nuclear facilities;
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;
access to capital markets 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 uncertainties of successful exploration of unconventional gas and oil resources and challenges in estimating gas and oil reserves with certainty;
changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
unplanned outages;
the cost of protecting assets against, or damage due to, terrorism or cyber attacks;
employee relations and the impact of collective bargaining agreements;
the availability, cost, coverage and terms of insurance and stability of insurance providers;
cost reduction efforts and the maximization of plant and distribution system performance;
the effects of competition;
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;
binding arbitration, litigation and related appeals; and
the risks discussed in our public filings with the Securities and Exchange Commission.

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 speak 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, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity.
Our other businesses are involved in 1) natural gas pipelines, gathering and storage; 2) unconventional gas and oil project development and production; 3) power and industrial projects and coal transportation and marketing; and 4) energy marketing and trading operations.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and all amendments to such reports are available free of charge through the Investors - Reports and Filings 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 23 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 Electric Utility segment consists principally 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, 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.
Non-Utility Operations
Gas Storage and Pipelines consists of natural gas pipelines, gathering and storage businesses.
Unconventional Gas Production is engaged in unconventional gas and oil project development and production.
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell

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electricity from biomass-fired energy projects.
Energy Trading consists of energy marketing and trading operations.
Corporate and Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.
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 principally of Detroit Edison. Our generating plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our fossil-fuel 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
 
2011
 
2010
 
2009
 
(In millions)
Residential
$
2,182

 
$
2,052

 
$
1,820

Commercial
1,704

 
1,629

 
1,702

Industrial
692

 
688

 
730

Other
458

 
479

 
299

Subtotal
5,036

 
4,848

 
4,551

Interconnection sales (1)
118

 
145

 
163

Total Revenue
$
5,154

 
$
4,993

 
$
4,714

_______________________________________
(1)
Represents power that is not distributed by Detroit Edison.
Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands. Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.
Fuel Supply and Purchased Power
Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts,

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with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short term contracts for the purchase of approximately 29 million tons of low-sulfur western coal to be delivered from 2012 through 2014 and approximately 6 million tons of Appalachian coal to be delivered from 2012 through 2014. All of these contracts have pricing schedules. We have approximately 95% of our 2012 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 four years. All of our expected 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 and real-time basis and bid for power in the market to serve our load. We are a net purchaser of power that supplements our generation capability to meet customer demand during peak cycles.
Properties
Detroit Edison owns generating plants and facilities that are located in the State of Michigan. Substantially all of our property is subject to the lien of a mortgage.

Generating plants owned and in service as of December 31, 2011 are as follows:
 
 
Location by
Michigan
 
Summer Net
Rated
Capability (1)
 
 
Plant Name
 
County
 
(MW)
 
(%)
 
Year in Service
Fossil-fueled Steam-Electric
 
 
 
 

 
 
 
 
Belle River (2)
 
St. Clair
 
1,047

 
10.0
 
1984 and 1985
Greenwood
 
St. Clair
 
782

 
7.5
 
1979
Harbor Beach
 
Huron
 
93

 
0.9
 
1968
Monroe (3)
 
Monroe
 
2,893

 
27.7
 
1971, 1973 and 1974
River Rouge
 
Wayne
 
525

 
5.0
 
1957 and 1958
St. Clair
 
St. Clair
 
1,382

 
13.3
 
1953, 1954, 1959, 1961 and 1969
Trenton Channel
 
Wayne
 
674

 
6.5
 
1949 and 1968
 
 
 
 
7,396

 
70.9
 
 
Oil or Gas-fueled Peaking Units
 
Various
 
1,026

 
9.8
 
1966-1971, 1981 and 1999
Nuclear-fueled Steam-Electric Fermi 2 (4)
 
Monroe
 
1,086

 
10.4
 
1988
Hydroelectric Pumped Storage
Ludington (5)
 
Mason
 
917

 
8.9
 
1973
 
 
 
 
10,425

 
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 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
(3)
The Monroe generating plant provided 38% of Detroit Edison’s total 2011 power generation.
(4)
Fermi 2 has a design electrical rating (net) of 1,150 MW.
(5)
Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.

In December 2011, the Connors Creek (239 MW) and Marysville (84 MW) generating plants and Unit No. 5 at the St. Clair generating plant (250 MW) were retired consistent with Detroit Edison's operational plan.
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 500 MW of owned or contracted renewable energy at December 31, 2011 representing approximately 6% of electricity sold to retail customers. Approximately

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120 MW is in commercial operation at December 31, 2011 with an additional 380 MW expected in commercial operation in 2012 or early 2013.

Detroit Edison owns and operates 671 distribution substations with a capacity of approximately 33,516,000 kilovolt-amperes (kVA) and approximately 428,300 line transformers with a capacity of approximately 24,421,000 kVA.
Circuit miles of electric distribution lines owned and in service as of December 31, 2011:
 
 
Circuit Miles
Operating Voltage-Kilovolts (kV)
 
Overhead
 
Underground
4.8 kV to 13.2 kV
 
28,544

 
14,105

24 kV
 
182

 
696

40 kV
 
2,277

 
382

120 kV
 
54

 
8

 
 
31,057

 
15,191


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 3, 8, 11 and 19 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. We also partner with federal, state and local officials to attempt to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low-income customers will affect the level of uncollectible expense.
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.
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 2011 and 2010 and 3% of retail sales in 2009. Customers

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participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed market costs. 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 had a Choice Incentive Mechanism, which was an over/under recovery mechanism that measured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. Effective with the October 2011 MPSC rate order, this mechanism has been terminated and our customer rates reflect the current level of electric Customer Choice sales. We expect that in 2012 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales.
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
 
2011
 
2010
 
2009
 
(In millions)
Gas sales
$
1,150

 
$
1,281

 
$
1,443

End user transportation
194

 
185

 
144

Intermediate transportation
58

 
69

 
69

Storage and other
103

 
113

 
132

Total Revenue
$
1,505

 
$
1,648

 
$
1,788


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 natural gas to storage fields, processing plants, pipeline interconnections or other locations.
Storage and other — Includes revenues from natural 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.


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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 2011. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased gas supplies. Because of our geographic diversity of supply and our pipeline transportation and storage capacity, we are able to reliably meet our supply requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to 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
(MMcf/d)
 
Contract
Expiration
Great Lakes Gas Transmission L.P. 
80
 
2013
Viking Gas Transmission Company
51
 
2013
Vector Pipeline L.P. 
50
 
2015
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 1,175,000 service pipelines and approximately 1,309,000 active meters. We own approximately 2,000 miles of transmission pipelines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas.
We own storage properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 138 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 67 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 18 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 the 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.

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We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
See Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
Energy Assistance Program
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to MichCon’s ability to control its uncollectible accounts receivable and collections expenses. MichCon’s uncollectible accounts receivable expense is directly affected by the level of government-funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory. We also partner with federal, state and local officials to attempt to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low- income customers will affect the level of uncollectible expense.
Strategy and Competition
Our strategy is to be the preferred provider of natural gas services 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, weather and natural gas pricing.
GAS STORAGE AND PIPELINES
Description
Gas Storage and Pipelines controls two natural gas storage fields and has ownership interests in two interstate pipelines serving the Midwest, Ontario and Northeast markets. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts.

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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
 
NY
MichCon Pipeline
 
100
%
 
543-mile pipeline
 
MI
Storage
 
 
 
 
 
 
Washington 10
 
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 10 and 28 storage facilities and for the MichCon pipeline.
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. We have competition from other pipelines and storage providers. 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. Much of the growth in demand for natural gas is expected to occur in the Eastern Canada and the Northeast U.S. regions. We believe that the Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. In addition, we believe that Millennium Pipeline is well positioned for growth related to production from the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York. Gas Storage and Pipelines has executed an agreement with Southwestern Energy Services Company to support its Bluestone lateral and gathering system. Bluestone is a 40 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York scheduled to be in service in 2012. We expect to continue steady growth in the Gas Storage and Pipelines business and are evaluating new pipeline and storage investment opportunities that could include additional Millennium expansions and laterals, Bluestone laterals and gathering expansions and other Marcellus midstream development or partnering opportunities.
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 have and will continue to target liquids rich gas and oil producing horizons. Total capital investment of $28 million and production of 5.1 Bcfe in 2011 were slightly higher than 2010. Oil production increased 58% over 2010 levels as a result of recent drilling in the Marble Falls formation, shallow reserves lying above the Barnett shale, while gas production showed a 3% decline. We executed on leasing opportunities to optimize our existing portfolio by acquiring acreage at attractive prices in 2011, bringing our total net acreage position to 87,377 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:
 
2011
 
2010
 
2009
Producing Wells (1)(2)(3)
214

 
194

 
174

Developed Lease Acreage (1)(3)(4)
16,768

 
15,928

 
14,968

Undeveloped Lease Acreage (1)(3)(5)
70,609

 
54,318

 
48,399

Production Volume (Bcfe)(6)
5.1

 
4.8

 
5.0

Proved Reserves (Bcfe)(7)
186

 
201

 
234

Capital Expenditures (in millions)
$
28

 
$
26

 
$
26

Future Undiscounted Cash Flows (in millions)(8)
$
448

 
$
478

 
$
392

Average Gas Price (per Mcf)
$
7.03

 
$
5.99

 
$
4.34

Average Oil Price (per Barrel)
$
92.79

 
$
76.41

 
$
58.47

_______________________________________
(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 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)
Production volume is reported on a Bcf equivalent basis using a standard ratio of one barrel of oil and/or natural gas liquids to 6 Mcf of natural gas equivalents.
 Production Volume By Product
 
 
 
 
 
 
2011
 
2010
 
2009
 
 
 
 
 
 
 Natural Gas
46
%
 
51
%
 
57
%
 Natural Gas Liquids
35

 
36

 
34

 Crude Oil
19

 
13

 
9

 
100
%
 
100
%
 
100
%

(7)
The decreases in proved reserves for 2011 and 2010 are primarily due to removal of 20 Bcfe and 17 Bcfe, respectively, of reserves that exceeded the five-year development limit for the Proved Undeveloped classification, and other revisions to estimates.
 Proved Reserves By Product
 
 
 
 
 
 
2011
 
2010
 
2009
 
 
 
 
 
 
 Natural Gas
50
%
 
54
%
 
57
%
 Natural Gas Liquids
39

 
41

 
40

 Crude Oil
11

 
5

 
3

 
100
%
 
100
%
 
100
%

(8)
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 that we may enter into from time to time.

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Strategy and Competition

We plan to focus on optimizing the productivity of our wells and to seek opportunities for monetization of properties in 2012. The majority of our acreage position has rights to shallow reserves lying above the Barnett shale, specifically the Marble Falls formation. Recent drilling efforts have been largely successful in finding oil and high BTU gas. We anticipate the continued development of this liquids play which is expected to add value to our asset base. We expect total capital investment of $30 - 35 million to drill approximately 30 new wells and continue to acquire select acreage and achieve production of approximately 6 - 7 Bcfe, compared with 5 Bcfe in 2011. The majority of the drilling activity is expected to occur during the first half of 2012.
Due to increased activity in other shale plays throughout the country, the availability of service providers has decreased. 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, 2011, we had no long-term fixed 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:
 
2012
Oil Volume (in MBbl)
72

Price (in Bbl)
$
101.73

POWER AND INDUSTRIAL PROJECTS
Description
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity from biomass-fired energy projects. This business segment provides 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 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 from steel industry fuel activities. 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. We provide utility-type services using project assets usually located on or near the customers' premises in the automotive, airport, chemical and other industries.
Wholesale Power and Renewables:  We own and operate four biomass-fired electric generating plants with a capacity of 183 MWs. We own a coal-fired power plant currently undergoing conversion to biomass with an expected in-service date in 2013. 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 Emissions Fuel: We own and operate nine reduced emissions fuel facilities. Our facilities blend a proprietary additive with coal used in coal-fired power plants resulting in reduced emissions of Nitrogen Oxide (NO) and Mercury (Hg). Qualifying facilities are eligible to generate tax credits for ten years upon achieving certain criteria. The value of a tax credit is adjusted annually by an inflation factor published annually by the Internal Revenue Service. The value of the tax credit is reduced if the reference price of coal exceeds certain thresholds. The economic benefit of the reduced emissions fuel facilities is dependent upon the generation of production tax credits. We placed in service five facilities in 2009 and an additional four facilities in 2011. To optimize income and cash flow from the reduced emissions fuel operations, we sold membership interests in 2011 at two of the facilities that are located at Detroit Edison sites, which in substance, represented a sale of production tax credits. Although both sales included a modest up-front payment from the tax investor, the bulk of the proceeds will be received, and the income for all of the proceeds will be recognized, as production tax credits are generated. We continue to optimize these facilities by seeking tax investors for facilities operating at Detroit Edison and other utility sites. Additionally, we intend to relocate certain underutilized facilities, located at Detroit Edison sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2012 and future years.

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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 services 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.
Properties and Other
The following are significant properties operated by the Power and Industrial projects segment:
Facility
 
Location
 
Service Type
Steel, Steel Industry Fuel, and Petroleum Coke
 
 
 
 
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 Water,
 
 
MI, IN, OH &
NY
 
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
Chemical Manufacturing
 
KY
 
Electricity, Steam and Natural Gas
 
 
 
 
 
Wholesale Power and Renewables
 
 
 
 
Pulp and Paper
 
AL
 
Electric Generation and Steam
Renewables
 
CA & WI
 
Electric Generation
Landfill Gas Recovery
 
Various U.S. sites
 
Electric Generation and Landfill Gas
 
 
 
 
 
Other Industries
 
 
 
 
Reduced Emissions Fuel
 
MI, OK, IL
 
Reduced Emission Fuel Supply
Coal Services
 
IL
 
Coal Terminal and Blending

 
2011
 
2010
 
2009
 
(In millions)
Production Tax Credits Generated (Allocated to DTE Energy)
 
 
 
 
 
Coke Battery (1)
$—
 
$—
 
$5
Steel Industry Fuels (2)
 
29
 
4
Power Generation
4
 
2
 
2
Landfill Gas Recovery
1
 
1
 
1
Reduced Emission Fuel
1
 
1
 
_______________________________________
(1)
Tax laws enabling production tax credits related to two coke battery facilities expired on December 31, 2009.
(2)
Tax laws enabling the steel industry fuel tax credits expired on December 31, 2010.

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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.
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 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.
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, 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 and producers which may include the management of associated storage and transportation contracts on the customers’ behalf under FERC Asset Management Arrangements. 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 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

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institutions, traders, utilities and other energy providers. The Energy 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 AND OTHER
Description
Corporate and 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
$
1,921

 
$

 
$

 
$
1,921

Water
80

 

 
13

 
93

Contaminated and other sites
17

 
37

 

 
54

Estimated total future expenditures through 2021
$
2,018

 
$
37

 
$
13

 
$
2,068

Estimated 2012 expenditures
$
255

 
$
17

 
$
10

 
$
282

Estimated 2013 expenditures
$
311

 
$
5

 
$
2

 
$
318

Air - Detroit Edison is subject to the EPA ozone and fine particulate 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, mercury and other air pollution. These rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and other emissions. Further, additional rulemakings could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants over the next few years.
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. In addition, there are proposed rules that may require the installation of cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines.
Contaminated 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 manufactured gas plant (MGP) sites. Gas Utility owns, or previously owned, fifteen such former MGP sites. Detroit Edison owns, or previously owned, three former MGP sites. 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 MGP environmental costs from having a material adverse impact on the Company’s results of operations.
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 these sites and affect the Company’s financial position and cash flows.

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The EPA has published proposed rules to regulate coal ash, which may result in a designation as a hazardous waste. The EPA 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.
See Notes 11 and 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report and Management’s Discussion and Analysis in Item 7 of this Report.

EMPLOYEES

We had approximately 9,800 employees as of December 31, 2011, of which approximately 5,000 were represented by unions. There are several bargaining units for the Company’s represented employees. The majority of represented employees are under contracts that expire in August 2012 and June and October 2013.

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.
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. Our utilities typically self-implement base rate changes six months after rate case filings in accordance with Michigan law. However, if the final rates authorized by our regulators in the final rate order are lower than the amounts we collected during the self-implementation period, we must refund the difference with interest. Our regulators may also disagree with our rate calculations under the various tracking and decoupling mechanisms that are intended to mitigate the risk to our utilities of certain aspects of our business. If we cannot agree with our regulators on an appropriate reconciliation of those mechanisms, it may impact our ability to recover certain costs through our customer rates. Our regulators may also decide to eliminate more of these mechanisms in future rate cases, which may make it more difficult for us to recover our costs in the rates we charge customers. We cannot predict what rates an MPSC order will adopt in future rate cases. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rates or require us to incur additional expenses.
Changes to 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 10 percent cap on the total potential Customer Choice related migration. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be legislative and financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and full service electric price changes.
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 and credit risk of counterparties we do business with. 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 deteriorate, reduced volumes of electricity and gas, and demand for energy services we supply, collections of accounts receivable, reductions in federal and state energy assistance funding, and potentially higher levels of lost or stolen gas could result in decreased earnings and cash flow.

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Environmental laws and liability may be costly.  We are subject to and affected by 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 and can negatively affect the affordability of the rates we charge to our customers.
Uncertainty around future environmental regulations creates difficulty planning long-term capital projects in our generation fleet and gas distribution businesses. 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.
Future environmental regulation of natural gas extraction techniques including hydraulic fracturing being discussed both at the United States federal level and by some states may affect the profitability of natural gas extraction businesses which could affect demand for and profitability of our gas transportation businesses.
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, changes in federal nuclear regulation and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.
The supply and/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. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. Our non-utility businesses, including our energy transportation business, are also dependent upon supplies and prices of energy commodities and services. Price fluctuations, fuel supply disruptions and changes in transportation costs could have a negative impact on the amounts we charge our utility customers for electricity and gas and on the profitability of our non-utility businesses. We have hedging strategies and regulatory recovery mechanisms in place to mitigate some of the negative fluctuations in commodity supply prices in our utility and non-utility businesses, 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 or provide energy transportation services.
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.
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 our 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

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markets. Our long term revolving credit facilities do not expire until 2015, but we regularly access capital markets to refinance existing debt or fund new projects at our utilities, and we cannot predict the pricing or demand for those future transactions.
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, resulting in 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.
Construction and capital improvements to our power facilities and distribution systems subject us to risk. We are managing ongoing and planning future significant construction and capital improvement projects at multiple power generation and distribution facilities and our gas distribution system. Many factors that could cause delays 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 and businesses.
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.
Our non-utility businesses may not perform to our expectations. We rely on our non-utility operations for a portion of our earnings. If our current and contemplated non-utility investments do not perform at expected levels, we could experience diminished earnings and a corresponding decline in our shareholder value.
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 generated production tax credits from coke production, landfill gas recovery, biomass fired electric generation, reduced emission fuel, renewable energy credits, steel industry fuel and gas production operations. All production tax credits

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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.
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.
Unplanned power plant outages may be costly.  Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.
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 existing 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. In addition, there could be additional state requirements increasing the percentage of power required to be provided by renewable energy sources. 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.
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.
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.
A work interruption may adversely affect us.  Unions represent approximately 5,000 of our employees. Our contract with one union representing about 500 of our electrical linemen is due to expire in August 2012. We cannot predict the outcome of those negotiations. 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.

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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.
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.

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 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 (NOV/FOV) 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 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 expects to enter into the Consent Order during the first quarter of 2012.
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. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants' business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney's fees and expenses. On October 15, 2009, the U.S. District Court granted defendants' motions dismissing all of plaintiffs' federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs' state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.
In July 2009, DTE Energy received a 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.
In August 2010, the United States Department of Justice, at the request of 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. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit.

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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 two NOVs/FOVs, Detroit Edison could 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 these matters, or the timing of its resolution.
In October 2010, the Company received a Notice of Violation from the Michigan Department of Natural Resources (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 the 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 Judgment 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 August 2011, Allegheny County Health Department (ACHD) issued an Enforcement Order alleging 114 incidents of fugitive pushing emissions at the coke battery facility in Pennsylvania and assessing a civil penalty of $114,000. The Company has appealed the Enforcement Order. The Company is in the process of negotiating a Consent Order with ACHD to settle this Enforcement Order. The Company expects to enter into the consent order in the first half of 2012. The Company is completing a maintenance program designed to minimize future fugitive pushing emissions from the coke battery facility.
For additional discussion on legal matters, see Notes 11 and 19 of the Notes to Consolidated Financial Statements in Item 8 of this Report.

Item 4. Mine Safety Disclosures

Not applicable.


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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock. The following table indicates the reported high and low sales prices of our common stock on the Composite Tape of the New York Stock Exchange and dividends paid per share for each quarterly period during the past two years:
 
 
 
 
 
 
 
 
Dividends
Paid per Share
Year
 
Quarter
 
High
 
Low
 
2011
 
 
 
 

 
 

 
 

 
 
First
 
$
49.36

 
$
45.17

 
$
0.5600

 
 
Second
 
$
52.78

 
$
48.06

 
$
0.5875

 
 
Third
 
$
52.00

 
$
43.22

 
$
0.5875

 
 
Fourth
 
$
55.28

 
$
47.03

 
$
0.5875

2010
 
 
 
 

 
 

 
 

 
 
First
 
$
45.93

 
$
41.25

 
$
0.5300

 
 
Second
 
$
49.05

 
$
43.00

 
$
0.5300

 
 
Third
 
$
49.06

 
$
44.93

 
$
0.5600

 
 
Fourth
 
$
47.66

 
$
44.27

 
$
0.5600

At December 31, 2011, there were 169,247,282 shares of our common stock outstanding. These shares were held by a total of 71,208 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 $389 million in 2011, $360 million in 2010, and $348 million in 2009. 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 13 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 21 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.
See the following table for information as of December 31, 2011.
 
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options
 
Weighted-Average
Exercise Price of
Outstanding Options
 
Number of Securities
Remaining Available for
Future Issuance Under Equity
Compensation Plans
Plans approved by shareholders
2,764,670
 
$41.25
 
1,945,035

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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act for the year ended December 31, 2011:
 
Number of
Shares
Purchased (1)
 
Average
Price
Paid per
Share (1)
 
Number
of Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
 
Average
Price Paid
per Share
 
Maximum Dollar
Value that May
Yet Be
Purchased Under
the Plans or
Programs
01/01/2011 — 01/31/2011
13,893

 
$
45.30

 

 

 

02/01/2011 — 02/28/2011
631,248

 
46.81

 

 

 

03/01/2011 — 03/31/2011
25,302

 
42.28

 

 

 

04/01/2011 — 04/30/2011
3,839

 
49.13

 

 

 

05/01/2011 — 05/31/2011
139,340

 
51.28

 

 

 

06/01/2011 — 06/30/2011
181,721

 
48.85

 

 

 

07/01/2011 — 07/31/2011
6,990

 
46.20

 

 

 

08/01/2011 — 08/31/2011
60,000

 
49.95

 

 

 

09/01/2011 — 09/30/2011
71,965

 
44.90

 

 

 

10/01/2011 — 10/31/2011
2,241

 
49.02

 

 

 

11/01/2011 — 11/30/2011
155,000

 
51.10

 

 

 

12/01/2011 — 12/31/2011
102,411

 
54.11

 

 

 

Total
1,393,950

 
 

 

 
 

 
 

_______________________________________
(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. Also includes shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.

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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
2007
 
2008
 
2009
 
2010
 
2011
DTE Energy Company
(5.03
)
 
(14.37
)
 
30.08

 
9.06

 
25.76

S&P 500 Index
5.49

 
(37.00
)
 
26.46

 
15.06

 
2.11

S&P 500 Multi-Utilities Index
10.86

 
(24.34
)
 
20.93

 
11.08

 
18.41


 
Indexed Returns
Year Ended December 31
 
Base
Period
 
 
 
 
 
 
 
 
 
 
Company/Index
2006
 
2007
 
2008
 
2009
 
2010
 
2011
DTE Energy Company
100

 
94.97

 
81.32

 
105.78

 
115.36

 
145.08

S&P 500 Index
100

 
105.49

 
66.46

 
84.05

 
96.71

 
98.76

S&P 500 Multi-Utilities Index
100

 
110.86

 
83.88

 
101.43

 
112.67

 
133.40

Comparison of Cumulative Five Year Total Return

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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.
 
2011
 
2010
 
2009
 
2008
 
2007
 
(In millions, except per share amounts)
Operating Revenues
$
8,897

 
$
8,557

 
$
8,014

 
$
9,329

 
$
8,475

Net Income Attributable to DTE Energy Company
 
 
 
 
 
 
 
 
 
Income from continuing operations (1)
$
711

 
$
630

 
$
532

 
$
526

 
$
787

Discontinued operations

 

 

 
20

 
184

Net Income Attributable to DTE Energy Company
$
711

 
$
630

 
$
532

 
$
546

 
$
971

Diluted Earnings Per Common Share
 
 
 
 
 
 
 
 
 
Income from continuing operations
$
4.18

 
$
3.74

 
$
3.24

 
$
3.22

 
$
4.61

Discontinued operations

 

 

 
0.12

 
1.08

Diluted Earnings Per Common Share
$
4.18

 
$
3.74

 
$
3.24

 
$
3.34

 
$
5.69

Financial Information
 
 
 
 
 
 
 
 
 
Dividends declared per share of common stock
$
2.32

 
$
2.18

 
$
2.12

 
$
2.12

 
$
2.12

Total assets
$
26,009

 
$
24,896

 
$
24,195

 
$
24,590

 
$
23,742

Long-term debt, including capital leases
$
7,187

 
$
7,089

 
$
7,370

 
$
7,741

 
$
6,971

Shareholders’ equity
$
7,009

 
$
6,722

 
$
6,278

 
$
5,995

 
$
5,853

_______________________________________
(1)
2011 results include an $87 million income tax benefit related to the enactment of the MCIT. 2008 results include an $80 million after-tax gain on the sale of a portion of the Barnett shale properties. 2007 results include a $580 million after-tax gain on the Antrim sale transaction and $210 million after-tax loss on hedge contracts associated with the Antrim sale.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE OVERVIEW
DTE Energy is a diversified energy company with 2011 operating revenues of approximately $8.9 billion and approximately $26 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:
 
2011
 
2010
 
2009
 
(In millions, except per share amounts)
Net income attributable to DTE Energy Company
$
711

 
$
630

 
$
532

Diluted earnings per common share
$
4.18

 
$
3.74

 
$
3.24


The increase in 2011 Net income attributable to DTE Energy as compared to 2010 was driven by higher earnings in Energy Trading, partially offset by lower earnings in the Electric and Gas Utilities and in the Power and Industrial Projects segment. The 2011 increase is also due to an income tax benefit of $87 million in the Corporate and Other segment related to the enactment of the MCIT in the second quarter of 2011. 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.

Please see detailed explanations of segment performance in the following Results of Operations section.

DTE Energy's strategy is to achieve long-term earnings growth, a strong balance sheet and an attractive dividend yield.


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Our utilities' growth will be driven by mandated environmental and renewable investments in addition to base infrastructure investments. We are focused on executing plans to achieve operational excellence and customer satisfaction with a focus on customer affordability. We operate in a constructive regulatory environment and have solid relationships with our regulators.
We have significant investments in our non-utility businesses. We employ disciplined investment criteria when assessing meaningful, low-risk growth opportunities that leverage our assets, skills and expertise and provide diversity in earnings and geography. 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.

A key priority for DTE Energy is to maintain a strong balance sheet which facilitates access to capital markets and reasonably priced short-term and long-term financing. Near-term growth will be funded through internally generated cash flows, expected monetization of our Unconventional Gas Production business, issuance of debt and issuance of equity through our dividend reinvestment plan and pension and other employee benefit plans. We have adopted an enterprise risk management program that, among other things, is designed to monitor and manage our exposure to earnings and cash flow volatility related to commodity price changes, interest rates and counterparty credit risk.
CAPITAL INVESTMENTS

Our utility businesses require significant base 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. Detroit Edison's capital investments over the 2012-2016 period are estimated at $4 billion for base capital investments, $1.3 billion to $1.8 billion for mandated environmental requirements and $900 million for renewable and energy efficiency expenditures. MichCon's capital investments over the 2012-2016 period are estimated at $675 million for base capital investments, $250 million for gas main renewal and $115 million for meter move out programs. Detroit Edison and MichCon both 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 implementing 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 routinely files renewable energy plans, requests for approval of renewable contracts and for recovery of renewable capital expenditures with the MPSC as the implementation of the 20-year renewable energy plan progresses.

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 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.
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.
Detroit Edison is subject to the EPA ozone and fine particulate 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. These 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 $1.7 billion through 2011. The Company estimates Detroit Edison will make capital expenditures of approximately $255 million in 2012 and up to approximately $1.9 billion of additional capital expenditures through 2021 based on current regulations.
Climate regulation and/or legislation has been proposed and discussed within the U.S. Congress and the EPA, however the current 112th Congress is not expected to pass any major energy or climate bills. Meanwhile, the EPA is implementing regulatory actions under the Clean Air Act to address emissions of greenhouse gases. EPA regulation of greenhouse gases (GHGs) began in 2011 and requires the best available control technology (BACT) for new 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

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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 Note 19 of the Notes to the Consolidated Financial Statements and Items 1. and 2. Business and Properties for further discussion of Environmental Matters.
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 improve employee engagement;
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.

 
2011
 
2010
 
2009
 
(In millions)
Net Income Attributable to DTE Energy by Segment:
 
 
 
 
 
Electric Utility
$
434

 
$
441

 
$
376

Gas Utility
110

 
127

 
80

Gas Storage and Pipelines
57

 
51

 
49

Unconventional Gas Production
(6
)
 
(11
)
 
(9
)
Power and Industrial Projects
38

 
85

 
31

Energy Trading
52

 
6

 
75

Corporate and Other
26

 
(69
)
 
(70
)
Net Income Attributable to DTE Energy Company
$
711

 
$
630

 
$
532


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Table of Contents

ELECTRIC UTILITY
Our Electric Utility segment consists principally of Detroit Edison.
Electric Utility results are discussed below:
 
2011
 
2010
 
2009
 
(In millions)
Operating Revenues
$
5,154

 
$
4,993

 
$
4,714

Fuel and Purchased Power
1,716

 
1,580

 
1,491

Gross Margin
3,438

 
3,413

 
3,223

Operation and Maintenance
1,370

 
1,305

 
1,277

Depreciation and Amortization
818

 
849

 
844

Taxes Other Than Income
240

 
237

 
205

Asset (Gains) Losses, Reserves and Impairments, Net
13

 
(6
)
 
(2
)
Operating Income
997

 
1,028

 
899

Other (Income) and Deductions
298

 
317

 
295

Income Tax Expense
265

 
270

 
228

Net Income Attributable to DTE Energy Company
$
434

 
$
441

 
$
376

Operating Income as a Percent of Operating Revenues
19
%
 
21
%
 
19
%
Gross margin increased $25 million in 2011 and increased $190 million in 2010. 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:
 
2011
 
2010
 
(In millions)
Rate case and Choice Incentive mechanism, net of Revenue Decoupling mechanism and sales volume
$
29

 
$
84

Restoration tracker
27

 
35

Securitization bond and tax surcharge
(39
)
 
40

Low Income Energy Efficiency Fund revenue deferral
(23
)
 

Energy optimization performance incentive
17

 

Regulatory mechanisms and other
14

 
31

Increase in gross margin
$
25

 
$
190


 
2011
 
2010
 
2009
 
(In thousands of MWh)
Electric Sales
 
 
 
 
 
Residential
15,907

 
15,726

 
14,625

Commercial
16,779

 
16,570

 
18,200

Industrial
9,739

 
10,195

 
9,922

Other
3,136

 
3,210

 
3,229

 
45,561

 
45,701

 
45,976

Interconnection sales (1)
3,512

 
4,876

 
5,156

Total Electric Sales
49,073

 
50,577

 
51,132

Electric Deliveries
 

 
 

 
 

Retail and Wholesale
45,561

 
45,701

 
45,976

Electric Customer Choice, including self generators
5,445

 
5,005

 
1,477

Total Electric Sales and Deliveries
51,006

 
50,706

 
47,453

______________________________
(1)
Represents power that is not distributed by Detroit Edison.

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Table of Contents

 
2011
 
2010
 
2009
 
(In thousands of MWh)
Power Generated and Purchased
 
 
 
 
 
 
 
 
 
 
 
Power Plant Generation
 
 
 
 
 
 
 
 
 
 
 
Fossil
35,502

 
68
%
 
39,433

 
73
%
 
40,595

 
74
%
Nuclear
8,910

 
17

 
7,738

 
14

 
7,406

 
14

 
44,412

 
85

 
47,171

 
87

 
48,001

 
88

Purchased Power
8,028

 
15

 
6,638

 
13

 
6,495

 
12

System Output
52,440

 
100
%
 
53,809

 
100
%
 
54,496

 
100
%
Less Line Loss and Internal Use
(3,367
)
 
 
 
(3,232
)
 
 
 
(3,364
)
 
 
Net System Output
49,073

 
 
 
50,577

 
 
 
51,132

 
 
Average Unit Cost ($/MWh)
 
 
 
 
 
 
 
 
 
 
 
Generation (1)
$
22.67

 
 
 
$
18.94

 
 
 
$
18.20

 
 
Purchased Power
$
42.78

 
 
 
$
42.38

 
 
 
$
37.74

 
 
Overall Average Unit Cost
$
25.75

 
 
 
$
21.83

 
 
 
$
20.53

 
 
_______________________________________
(1)
Represents fuel costs associated with power plants.
Operation and maintenance expense increased $65 million in 2011 and increased $28 million in 2010. The increase in 2011 is primarily due to higher restoration and line clearance expenses of $41 million, higher generation maintenance and outage expenses of $25 million, higher energy optimization and renewable energy expenses of $19 million, higher employee benefit expense of $9 million, partially offset by reduced contributions of $23 million to the Low Income Energy Efficiency Fund due to a court order, and reduced uncollectible expenses of $7 million. 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.
Depreciation and amortization expense decreased $31 million in 2011 due primarily to reduced amortization of regulatory assets, partially offset by expense related to higher depreciable base. Depreciation and amortization expense was $5 million higher in 2010 due primarily to expense related to 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.
Asset (gains) and losses, reserves and impairments, net increased $19 million in 2011 principally attributable to an accrual of $19 million resulting from management's revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos removal obligation and other items. See Note 8 of the Notes to the Consolidated Financial Statements.

Outlook  - The base rate and rehearing orders approved by the MPSC in fourth quarter 2011 provide for an annual revenue increase of $188 million and an authorized return on equity of 10.5%. The base rate order terminated Detroit Edison's Restoration, Line Clearance and Uncollectible Expense tracking mechanisms. Termination of these trackers may result in increased volatility in Detroit Edison's results due to weather, the number of storms and uncollectible accounts receivable. The Choice Incentive Mechanism was also terminated in the base rate order. Base rates included electric Customer Choice sales at the capped 10 percent level. See Note 11 of Notes to the Consolidated Financial Statements for further discussion of the rate orders received by Detroit Edison.
 
We continue to move forward in our efforts to achieve operational excellence, sustained strong cash flows and earn our authorized return on equity. We expect that our planned significant environmental and renewable expenditures will result in earnings growth. Looking forward, additional factors may impact earnings such as the outcome of regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.


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Table of Contents

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results are discussed below:
 
2011
 
2010
 
2009
 
(In millions)
Operating Revenues
$
1,505

 
$
1,648

 
$
1,788

Cost of Gas
744

 
870

 
1,057

Gross Margin
761

 
778

 
731

Operation and Maintenance
394

 
378

 
415

Depreciation and Amortization
89

 
92

 
107

Taxes Other Than Income
54

 
55

 
49

Asset (Gains) and Losses, Net

 

 
(18
)
Operating Income
224

 
253

 
178

Other (Income) and Deductions
54

 
59

 
59

Income Tax Expense
60

 
67

 
39

Net Income Attributable to DTE Energy Company
$
110

 
$
127

 
$
80

Operating Income as a Percent of Operating Revenues
15
%
 
15
%
 
10
%
Gross margin decreased $17 million in 2011 and increased $47 million in 2010. 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:
 
2011
 
2010
 
(In millions)
Uncollectible tracking mechanism
$
(27
)
 
$
(43
)
2010 self-implementation and rate order
(4
)
 
125

Revenue decoupling mechanism
5

 

Energy optimization performance incentive
7

 

Midstream storage and transportation revenues
(12
)
 
(20
)
Subsidiaries transferred to Gas Storage and Pipelines segment
(17
)
 

Weather
25

 
(23
)
Lost and stolen gas

 
13

Other
6

 
(5
)
Increase (decrease) in gross margin
$
(17
)
 
$
47


 
2011
 
2010
 
2009
Gas Markets (in Bcf)
 
 
 
 
 
Gas sales
123

 
118

 
137

End user transportation
141

 
140

 
124

 
264

 
258

 
261

Intermediate transportation
273

 
391

 
463

 
537

 
649

 
724

Operation and maintenance expense increased $16 million in 2011 and decreased $37 million in 2010. The increase in 2011 is primarily due to the 2010 deferral of $32 million of previously expensed CTA restructuring expenses and increased energy optimization expenses of $10 million, partially offset by reduced uncollectible expenses of $13 million, reduced expenses for subsidiaries transferred to Gas Storage and Pipelines segment of $6 million, lower customer service expenses of $5 million, and lower gas operations expenses of $4 million. The decrease in 2010 is primarily due to reduced uncollectible

31

Table of Contents

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 contributions of $3 million to the Low Income Energy Efficiency Fund.
Outlook — We continue to move forward in our efforts to achieve operational excellence and sustained strong cash flows and earn our authorized return on equity. We plan to file a base rate case in the second quarter 2012 and expect to self-implement new rates in the fourth quarter 2012 at the beginning of the heating season. 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, additional factors may impact earnings such as infrastructure improvement capital programs, the outcome of future regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity, minimize lost and stolen gas, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.
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:
 
2011
 
2010
 
2009
 
(In millions)
Operating Revenues
$
91

 
$
83

 
$
82

Operation and Maintenance
16

 
14

 
15

Depreciation and Amortization
6

 
5

 
5

Taxes Other Than Income
3

 
2

 
2

Operating Income
66

 
62

 
60

Other (Income) and Deductions
(28
)
 
(25
)
 
(23
)
Income Tax Expense
35

 
32

 
33

Net Income
59

 
55

 
50

Noncontrolling interest
2

 
4

 
1

Net Income Attributable to DTE Energy
$
57

 
$
51

 
$
49

Net income attributable to DTE Energy increased $6 million and $2 million in 2011 and 2010, respectively. The 2011 increase was primarily driven by earnings from subsidiaries that were transferred from Gas Utility, increased earnings from our pipeline equity investments, and a settlement for customer gas treating services performed in prior years. The 2010 increase was driven by higher gas storage revenues and lower project development costs.
Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. Millennium Pipeline has secured customers for its Phase 1 & 2 expansions which are scheduled to be in-service in the fourth quarter of 2012 and the fourth quarter of 2013, respectively. Millennium's total capacity with the Phase 1 & 2 expansion will increase from 525,000 dth/d to over 800,000 dth/d. In addition, we have executed an agreement with Southwestern Energy Services Company to support our Bluestone lateral and gathering system. Bluestone is a 40 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow 250,000 dth/d to both Millennium Pipeline and Tennessee Pipeline and is scheduled to be in service in 2012. We plan to spend up to $280 million over the next five years on the Bluestone lateral and gathering system.

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Table of Contents

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.
Unconventional Gas Production results are discussed below:
 
2011
 
2010
 
2009
 
(In millions)
Operating Revenues
$
39

 
$
32

 
$
31

Operation and Maintenance
21

 
16

 
15

Depreciation, Depletion and Amortization
18

 
15

 
16

Taxes Other Than Income
3

 
2

 
1

Asset (Gains) and Losses, Net

 
10

 
6

Operating Income (Loss)
(3
)
 
(11
)
 
(7
)
Other (Income) and Deductions
6

 
6

 
6

Income Tax Benefit
(3
)
 
(6
)
 
(4
)
Net Income (Loss) Attributable to DTE Energy Company
$
(6
)
 
$
(11
)
 
$
(9
)

Unconventional Gas Production results were impacted by the impairment of expired or expiring leasehold positions in 2010 and 2009. Revenues and expenses increased in 2011 and 2010 as a result of new wells on line, increased liquids prices and higher crude oil production.

Outlook — We plan to focus on optimizing the productivity of our wells and to seek opportunities for monetization of properties in 2012. The majority of our acreage position has rights to shallow reserves lying above the Barnett shale, specifically the Marble Falls formation. Recent drilling efforts have been largely successful in finding oil and high BTU gas. We anticipate the continued development of this liquids play which is expected to add value to our asset base. We expect total capital investment of $30 - 35 million to drill approximately 30 new wells and continue to acquire select acreage and achieve production of approximately 6 - 7 Bcfe, compared with 5 Bcfe in 2011. The majority of the drilling activity is expected to occur in the first half of 2012.

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Table of Contents

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, marketing and trading services; and sell electricity from biomass-fired energy projects.
Power and Industrial Projects results are discussed below:
 
2011
 
2010
 
2009
 
(In millions)
Operating Revenues
$
1,129

 
$
1,144

 
$
661

Operation and Maintenance
1,025

 
978

 
593

Depreciation and Amortization
60

 
60

 
40

Taxes other than Income
10

 
14

 
9

 Asset (Gains) and Losses, Reserves and Impairments, Net
(12
)
 
(14
)
 
(6
)
Operating Income
46

 
106

 
25

Other (Income) and Deductions
(10
)
 
13

 
(1
)
Income Taxes
 
 
 
 
 
Expense
17

 
36

 
5

Production Tax Credits
(6
)
 
(33
)
 
(12
)
 
11

 
3

 
(7
)
Net Income
45

 
90

 
33

Noncontrolling interest
7

 
5

 
2

Net Income Attributable to DTE Energy Company
$
38

 
$
85

 
$
31

VIEs — As discussed in Note 1 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 result of the consolidation of these VIEs, Operating Revenues and Operation and Maintenance expense increased $174 million and $122 million, respectively, in 2010.
Operating revenues decreased $15 million in 2011 and increased $309 million in 2010, net of VIE adjustments. The 2011 decrease is primarily due to $166 million of lower coal transportation and marketing services related to an expired rail transportation contract at significantly below market rates, $21 million of lower volumes associated with the coal blending business and a $20 million decrease from the sale of our rail services business in 2010, partially offset by a $92 million increase related to reduced emissions fuels projects, $74 million increase in coke demand and pricing, and a $26 million increase in new on-site energy services projects. 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.
Operation and maintenance expense increased $47 million in 2011 and increased $263 million in 2010, net of VIE adjustments. The 2011 increase is due primarily to a $103 million increase in coal costs, a $93 million increase related to reduced emission fuels projects, and a $25 million increase in new on-site energy services projects, partially offset by $127 million lower coal transportation and marketing services related to the expired rail transportation contract, $19 million decrease from the sale of our rail services business in 2010, $17 million lower volumes primarily associated with the coal blending business and $11 million of lower coke battery operating costs. The 2010 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.
Asset (Gains) Losses decreased by $2 million in 2011 and increased by $8 million in 2010. The 2011 decrease was due to an asset impairment related to our landfill gas recovery business of $11 million, partially offset by installment gains of $9 million from the sale of a coke battery. The 2010 increase is due primarily to the sale of DTE Rail Services and an increase in installment gains from the sale of a coke battery.

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Table of Contents

Other (income) and deductions were higher by $23 million in 2011 and lower by $14 million in 2010. The increase in 2011 was due primarily to the production of refined coal from our reduced emissions fuels projects giving rise to tax credits which the Company has sold to third parties and gains on the extinguishment of debt related to our landfill gas recovery business. The decrease in 2010 was due primarily to lower equity earnings in various projects and higher intercompany interest associated with project investment.
Production tax credits decreased by $27 million in 2011 due primarily to the expiration of steel industry fuels credits as of December 31, 2010, partially offset by tax credits earned from reduced emission fuel projects. The increase of $21 million in 2010 was due primarily to a full year of steel industry fuels tax credits.
Outlook — The Company has constructed and placed in service nine reduced emission fuel facilities. The Company has sold a membership interest in two of these facilities that are located at the Detroit Edison sites. Additionally, the Company has constructed two facilities located at third party owned coal-fired power plants. We continue to optimize these facilities by seeking tax investors for facilities operating at Detroit Edison and other utility sites. Additionally, we intend to relocate four underutilized facilities, located at Detroit Edison sites, to alternative coal-fired power plants which may provide increased production and emission reduction opportunities in 2012 and future years. The executed and planned sales of membership interests in the reduced emission fuel facilities represent, in substance, the sale of production tax credits. The proceeds from these sales are expected to be received by the Company on an installment basis, and the Company will recognize the related income as production tax credits are generated by the respective facilities.
We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2012. Substantially all of the metallurgical coke is under long-term contracts. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. 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 four facilities that will be in operation in 2012, we are converting an additional facility to be placed in service in 2013. We will continue to look for additional investment opportunities and other energy projects at favorable prices.
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 pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and related services, and the supply or purchase of renewable energy credits to various utilities which may include the management of associated storage and transportation contracts on the customers’ behalf.
Energy Trading results are discussed below:
 
2011
 
2010
 
2009
 
(In millions)
Operating Revenues
$
1,276

 
$
875

 
$
804

Fuel, Purchased Power and Gas
1,112

 
786

 
603

Gross Margin
164

 
89

 
201

Operation and Maintenance
63

 
59

 
71

Depreciation and Amortization
3

 
5

 
5

Taxes Other Than Income
3

 
2

 
3

Operating Income
95

 
23

 
122

Other (Income) and Deductions
9

 
12

 
10

Income Tax Expense
34

 
5

 
37

Net Income Attributable to DTE Energy Company
$
52

 
$
6

 
$
75

Gross margin increased $75 million in 2011 and decreased $112 million in 2010. The overall increase in gross margin in 2011 was the result of improved economic performance, coupled with the absence of prior year timing losses. We experienced timing-related earnings volatility based on market movement related to derivative contracts.

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Table of Contents

The increase in 2011 represents a $25 million increase in realized margins and $50 million increase in unrealized margins. The $25 million increase in realized margins is due to $73 million of favorable results, primarily in our power and gas trading and power full requirements strategies, offset by $48 million of unfavorable results, primarily in our power origination, gas structured and gas full requirements strategies. The $50 million increase in unrealized margins is due to $63 million of favorable results, primarily in our power full requirements, gas structured and gas trading strategies, offset by $13 million of unfavorable results, primarily in our power transmission strategy.
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.
Operation and maintenance expense increased $4 million in 2011 and decreased $12 million in 2010. The 2011 increase was primarily due to higher incentive costs and the 2010 decrease was primarily due to lower incentive costs, both of which were impacted by economic performance.
Income tax provision increased $29 million in 2011, due to higher pretax income. Income taxes decreased $32 million in 2010, 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.
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.
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 related services, and the supply or purchase of renewable energy credits to various utilities and producers which may include the management of associated storage and transportation contracts on the customers' behalf under FERC Asset Management Arrangements. 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 AND OTHER
Corporate and Other includes various holding company activities and holds certain non-utility debt and energy-related investments.
The 2011 net income of $26 million was an improvement of $95 million from the 2010 net loss of $69 million. The improvement resulted primarily from an income tax benefit of $87 million related to the enactment of the MCIT in the second quarter of 2011 and lower interest costs. See Note 12 of the Notes to Consolidated Financial Statements in Item 8 of this report.
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 and increased financing costs of $5 million.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements