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, | ||||
| 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 | |
| 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 ofRegulation 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 ofRegulation 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 thisForm 10-K or any amendment to thisForm 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 Rule12b-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 inRule 12b-2 of the Exchange Act). Yes o No þ
On June 30, 2010,2011, the aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates was approximately $7.8$8.5 billion (based on the New York Stock Exchange closing price on such date). There were 169,443,420169,403,378 shares of common stock outstanding at January 31, 2011.
2012.
Certain information in DTE Energy Company’s definitive Proxy Statement for its 20112012 Annual Meeting of Common Shareholders to be held May 5, 2011,3, 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 onForm 10-K, is incorporated herein by reference to Part III (Items 10, 11, 12, 13 and 14) of thisForm 10-K.
DTEEnergy Company
Annual Report onForm 10-K
Year Ended December 31, 20102011
TABLE OF CONTENTS
| Page | ||||||||
| 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 | ||||||||
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 | ||
| 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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ORWARD-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 referspeak only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.
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Part I
Items 1. and 2. Business and Properties
General
In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of Detroit Edison and MichCon. We also have four other segments that are engaged in a variety of energy-related businesses.
Detroit Edison is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the MPSC and the FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan.
MichCon is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transportation, gathering, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity.
Our other segmentsbusinesses are involved in 1) natural gas storagepipelines, gathering and pipelines;storage; 2) unconventional gas and oil project development and production; 3) power and industrial projects;projects and coal transportation and marketing; and 4) energy marketing and trading operations.
Our annual reports onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, proxy statements, and all amendments to such reports are available free of charge through the Investor RelationsInvestors - 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 at1-800-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 atwww.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 2423 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 |
Gas Utility
| The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, |
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Non-Utility Operations
| Gas Storage and Pipelines consists of natural gas pipelines, gathering and storage | ||
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 andenergy-related investments. 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 MDNRE.MDEQ. Electricity is generated from our several fossilfossil-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
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Residential | $ | 2,052 | $ | 1,820 | $ | 1,726 | ||||||
| Commercial | 1,629 | 1,702 | 1,753 | |||||||||
| Industrial | 688 | 730 | 894 | |||||||||
| Other | 479 | 299 | 289 | |||||||||
| Subtotal | 4,848 | 4,551 | 4,662 | |||||||||
| Interconnection sales(1) | 145 | 163 | 212 | |||||||||
| Total Revenue | $ | 4,993 | $ | 4,714 | $ | 4,874 | ||||||
| 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. |
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Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands. Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.
Fuel Supply and Purchased Power
Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts,
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with the balance to be obtained through short-term agreements and spot purchases. We have long-term and short-termshort term contracts for a totalthe purchase of approximately 3029 million tons of low-sulfur western coal to be delivered from 20112012 through 20132014 and approximately 56 million tons of Appalachian coal to be delivered from 20112012 through 2012.2014. All of these contracts have pricing schedules. We have approximately 98%95% of our 20112012 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 fivefour 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 real-time and FTRreal-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, 20102011 are as follows:
| Summer Net | ||||||||||||||
| Location by | Rated | |||||||||||||
| Michigan | Capability(1) | |||||||||||||
| Plant Name | County | (MW) | (%) | Year in Service | ||||||||||
| Fossil-fueled Steam-Electric | ||||||||||||||
| Belle River(2) | St. Clair | 1,044 | 9.5 | 1984 and 1985 | ||||||||||
| Conners Creek | Wayne | 239 | 2.1 | 1951 | ||||||||||
| Greenwood | St. Clair | 785 | 7.1 | 1979 | ||||||||||
| Harbor Beach | Huron | 94 | 0.9 | 1968 | ||||||||||
| Marysville | St. Clair | 84 | 0.8 | 1943 and 1947 | ||||||||||
| Monroe(3) | Monroe | 3,027 | 27.6 | 1971, 1973 and 1974 | ||||||||||
| River Rouge | Wayne | 523 | 4.8 | 1957 and 1958 | ||||||||||
| St. Clair(4) | St. Clair | 1,368 | 12.5 | 1953, 1954, 1959, 1961 and 1969 | ||||||||||
| Trenton Channel | Wayne | 698 | 6.4 | 1949 and 1968 | ||||||||||
| 7,862 | 71.7 | |||||||||||||
| Oil or Gas-fueled Peaking Units | Various | 1,101 | 10.0 | 1966-1971, 1981 and 1999 | ||||||||||
| Nuclear-fueled Steam-Electric Fermi 2(5) | Monroe | 1,087 | 9.9 | 1988 | ||||||||||
| Hydroelectric Pumped Storage Ludington(6) | Mason | 917 | 8.4 | 1973 | ||||||||||
| 10,967 | 100.0 | |||||||||||||
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 |
| (3) | The Monroe |
| (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 |
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 674671 distribution substations with a capacity of approximately 33,585,00033,516,000 kilovolt-amperes (kVA) and approximately 412,100428,300 line transformers with a capacity of approximately 23,849,00024,421,000 kVA.
Circuit miles of electric distribution lines owned and in service as of December 31, 2010:2011:
| Circuit Miles | ||||||||
| Operating Voltage-Kilovolts (kV) | Overhead | Underground | ||||||
| 4.8 kV to 13.2 kV | 28,345 | 13,916 | ||||||
| 24 kV | 181 | 696 | ||||||
| 40 kV | 2,278 | 381 | ||||||
| 120 kV | 54 | 13 | ||||||
| 30,858 | 15,006 | |||||||
| 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’sEdison'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’sEdison'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’sEdison's nuclear plant operations. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
See Notes 4, 9, 123, 8, 11 and 2019 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. We are minimizing the impacts of changes in average customer usage through regulatory mechanisms which decouple our revenue levels from sales volumes.
The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services, subject to limits. Customers choosing to purchase power from alternative electric suppliers represented approximately 10% of retail sales in 2011 and 2010 and 3% of retail sales in 2009 and 2008.. 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 their cost of service.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 havehad a Choice Incentive Mechanism, which iswas an over/under recovery mechanism that measuresmeasured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annualEffective 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 exceed the baseline amount from Detroit Edison’s most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decrease below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers.sales. We expect that in 20112012 customers choosing to purchase power from alternative electric suppliers will represent approximately 10% of retail sales.
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Competition in the regulated electric distribution business is primarily from theon-site generation of industrial customers and from distributed generation applications by industrial and commercial customers. We do not expect significant competition for distribution to any group of customers in the near term.
GAS UTILITY
Description
Our Gas Utility segment consists of MichCon and Citizens.
Revenue is generated by providing the following major classes of service: gas sales, end user transportation, intermediate transportation, and gas storage.
Revenue by Service
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Gas sales | $ | 1,281 | $ | 1,443 | $ | 1,824 | ||||||
| End user transportation | 185 | 144 | 143 | |||||||||
| Intermediate transportation | 69 | 69 | 73 | |||||||||
| Storage and other | 113 | 132 | 112 | |||||||||
| Total Revenue | $ | 1,648 | $ | 1,788 | $ | 2,152 | ||||||
| 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 2010.2011. 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
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requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to the New York Mercantile Exchange and published price indices to approximate current market prices combined with MPSC approved fixed price supplies with varying terms and volumes through 2014.
We are directly connected to interstate pipelines, providing access to most of the major natural gas supply producing regions in the Gulf Coast, Mid-Continent and Canadian regions. Our primary long-term transportation supply contracts are as follows:
| Availability | Contract | |||||||
| (MMcf/d) | Expiration | |||||||
| Vector Pipeline L.P. | 50 | 2012 | ||||||
| Great Lakes Gas Transmission L.P. | 80 | 2013 | ||||||
| Viking Gas Transmission Company | 51 | 2013 | ||||||
| ANR Pipeline Company | 195 | 2017 | ||||||
| Panhandle Eastern Pipeline Company | 75 | 2029 | ||||||
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 1,036,0001,175,000 service linespipelines and approximately 1,319,0001,309,000 active meters. We own approximately 2,000 miles of transportation linestransmission 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 134138 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 60267 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 1918 of the Notes to Consolidated Financial Statements in Item 8 of the Report.
Regulation
MichCon also provides interstate storage and transportation services in accordance with an Operating Statement on file with the FERC. The FERC’sFERC'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 1211 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
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Energy Assistance Program
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to MichCon’s ability to control its uncollectible accounts receivable and collections expenses. MichCon’s uncollectible accounts receivable expense is directly affected by the level of government-funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory. 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 owns partnershipcontrols two natural gas storage fields and has ownership interests in two interstate transmission pipelines serving the Midwest, Ontario and two natural gas storage fields.Northeast markets. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transportation pipeline, which connects Michigan to Chicago and Ontario. We also hold partnership interests in Millennium Pipeline Company which indirectly connects southern New York State to Upper Midwest/Canadian supply, while providing transportation service into the New York City markets. We have storage assets in Michigan capable
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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 | ||||||||||||
| 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 Washington 10 storage facilities.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 theMidwest-to-Northeast region to supply natural gas to meet growing demand. We expect muchMuch of the growth in the demand for natural gas is expected to occur in the U.S. to occur withinEastern Canada and the Mid-Atlantic and New EnglandNortheast U.S. regions. We forecastbelieve that the Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these regions will require incremental pipeline and gas storage infrastructure necessary to deliver gas volumes to meet growing demand. Vector is an interstate pipelinemarkets. In addition, we believe that is filling a large portion of that need, and is complemented by our Michigan storage facilities. Due to the proximity of the Millennium Pipeline is well positioned for growth related to production from the Marcellus shale, especially with respect to Marcellus production in Southern New York/Northern Pennsylvania we anticipate thatand along the Millennium Pipeline may have opportunitiessouthern tier of New York. Gas Storage and Pipelines has executed an agreement with Southwestern Energy Services Company to expandsupport 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 future.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 this year have and will continue to target liquids rich gas and oil producing locations.horizons. Total capital investment of $26$28 million and production of 55.1 Bcfe remained consistent with 2009.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 2010,2011, bringing our total net acreage position to 70,24687,377 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:
| 2010 | 2009 | 2008 | ||||||||||
| Producing Wells(1)(2)(3) | 194 | 174 | 162 | |||||||||
| Developed Lease Acreage(1)(3)(4) | 15,928 | 14,968 | 14,248 | |||||||||
| Undeveloped Lease Acreage(1)(3)(5) | 54,318 | 48,399 | 46,187 | |||||||||
| Production Volume (Bcfe) | 4.8 | 5.0 | 5.0 | |||||||||
| Proved Reserves (Bcfe)(6) | 201 | 234 | 167 | |||||||||
| Capital Expenditures (in millions)(3) | $ | 26 | $ | 26 | $ | 100 | ||||||
| Future Undiscounted Cash Flows (in millions)(7) | $ | 478 | $ | 392 | $ | 324 | ||||||
| Average Gas Price, excluding hedge contracts (per Mcf) | $ | 5.99 | $ | 4.34 | $ | 8.69 | ||||||
| Average Oil Price, excluding hedge contracts (per Barrel) | $ | 76.41 | $ | 58.47 | $ | 90.27 | ||||||
| 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 |
| (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 |
| 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 |
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Strategy and Competition
From time to time, we may use financial derivative contracts to manage a portion of our exposure to changes in the price of natural gas and oil on our forecasted sales volume. At December 31, 2010,2011, we had no long-term fixed
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price contracts relating to natural gas and had the following financial contracts in place with our Energy Trading affiliate related to our projected oil production:
| 2011 | ||||
| Oil Volume (in MBbl) | 72 | |||
| Price (in Bbl) | $ | 93.28 | ||
| 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’customers' premises in the steel, automotive, pulp and paper, airport and other industries as follows:
Steel, Steel Industry Fuel, and Petroleum Coke: We produce metallurgical coke from two coke batteries with a capacity of 1.4 million tons per year. We have an investment in a third coke battery with a capacity of 1.2 million tons per year. We are investors in steel industry fuel entities which sell steel industry fuel at three coke battery sites. Steel industry fuels facilities recycle tar decanter sludge, a byproduct of the coking process. Tax credits were generated in 2009 and 2010.2010 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. This business segment providesWe provide utility-type services using project assets usually located on or near the customers’customers' premises in the automotive, airport, chemical and other industries.
Wholesale Power and Renewables: We own and operate threefour biomass-fired electric generating plants with a capacity of 133183 MWs. We own twoa coal-fired power plantsplant currently undergoing conversionsconversion to biomass with an expected in-service dates of the fourth quarter of 2011 and the first quarter ofdate in 2013. We own one gas-fired peaking electric generating plant. The electric output is sold under long term power purchase agreements. We also develop landfill gas recovery systems that capture the gas and provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy, in addition to providing environmental benefits by reducing greenhouse gas emissions.
Reduced Emission Fuel: We deliver reduced emission fuel to utilities with coal-fired electric generation power plants.Emissions Fuel: We own and operate fivenine reduced emissions fuel facilities. Our facilities that process rawblend a proprietary additive with coal into reduced emission fuelused in coal-fired power plants resulting in reductions inreduced emissions of Nitrogen Oxide (NO) and Mercury (Hg) emissions.. 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 began generatingplaced 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 from these facilities beginning in 2009 which will continue through 2019 upon achieving certain criteria, including entering into transactions with unrelated equity partners or third-party customers for the reduced emission fuel.are generated. We continue to optimize these facilities by seeking tax investors for facilities operating at Detroit Edison sites, and other utility sites. Additionally, we intend to relocate othercertain underutilized facilities, located at Detroit Edison sites, to alternative sitescoal-fired power plants which may provide increased production and emission reduction opportunities in 20112012 and future years. In January 2011, the Company entered into an agreement to sell a membership interest in one
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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.
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Properties and Other
The following are significant properties operated by the Power and Industrial projects segment:
| Facility | Location | Service Type | ||
Steel, 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 | ||||
| Steam and Chilled Water | ||||
| Airports | MI & PA | Electricity, Hot and Chilled Water | ||
| Chemical Manufacturing | KY | Electricity, Steam and Natural Gas | ||
Wholesale Power | ||||
| Pulp and Paper | AL | Electric Generation and Steam | ||
| Renewables | CA & WI | Electric Generation | ||
| Landfill Gas Recovery | Various U.S. | Electric | ||
Other Industries | ||||
| Reduced | MI, OK, IL | Reduced Emission Fuel Supply | ||
| Coal | IL | Coal Terminal and Blending | ||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
Production Tax Credits Generated (Allocated to DTE Energy) | ||||||||||||
| Coke Battery(1) | $ | — | $ | 5 | $ | 5 | ||||||
| Steel Industry Fuels(2) | 29 | 4 | — | |||||||||
| Power Generation | 2 | 2 | 2 | |||||||||
| Landfill Gas Recovery | 1 | 1 | — | |||||||||
| Reduced Emission Fuel | 1 | — | — | |||||||||
| 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, |
| (2) | Tax laws enabling the steel industry fuel tax credits expired on December 31, |
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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.
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Strategy and Competition
Power and Industrial Projects will continue leveraging its energy-related operating experience and project management capability to develop and grow our steel; renewable power;on-site energy; coal marketing, storage and blending; landfill gas recovery; and reduced emission fuel businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties. There are limited competitors for our existing disparate businesses who provide similar products and services.
We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we examine closely the regulatory and competitive environment, new and pending legislation, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-relatedrelated 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; | ||
Providing operating services to leverage its existing business in 2011. Trends such as railroadowners of industrial and mining consolidation and the lack of certainty in developing new mines could have an impact on how we compete in the future. Effective January 1, 2011, our existing long-term rail transportation contract, at rates significantly below the current market, expired and we anticipate a decrease in transportation-related revenue of approximately $130 million as a result. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers.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.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 themark-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 aremarked-to-market without revaluing the underlying non-derivative contracts and assets. The segment’s strategy is to economically manage the price risk of these underlying non-derivative contracts and assets with futures, forwards, swaps and options. This results in gains and losses that are recognized in different interim and annual accounting periods.
Regulation
Energy Trading has market-based rate authority from the FERC to sell power and blanket authority from the FERC to sell natural gas at market prices. Energy Trading is subject to FERC reporting requirements and market
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behavior rules. Energy Trading is also subject to the applicable laws, rules and regulations related to the Commodity Futures Trading Commission, U.S. Department of Homeland Security and Department of Energy.
Strategy and Competition
Our strategy for the energy tradingEnergy 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 tradingEnergy 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 | $ | 2,100 | $ | — | $ | — | $ | 2,100 | ||||||||
| Water | 55 | — | 13 | 68 | ||||||||||||
| MGP sites | 4 | 36 | — | 40 | ||||||||||||
| Other sites | 21 | 1 | — | 22 | ||||||||||||
| Estimated total future expenditures through 2020 | $ | 2,180 | $ | 37 | $ | 13 | $ | 2,230 | ||||||||
| Estimated 2011 expenditures | $ | 239 | $ | 11 | $ | 3 | $ | 253 | ||||||||
| Estimated 2012 expenditures | $ | 276 | $ | 7 | $ | 7 | $ | 290 | ||||||||
| 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 mercuryother air pollution. The newThese rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and mercuryother emissions. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. It is not possible to quantifypollutants over the impact of those expected rulemakings at this time.next few years.
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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 thethese sites and affect the Company’s financial position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City
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The EPA has published proposed rules to regulate coal ash, under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either, to designate coal ash aswhich may result in a “Hazardous Waste” as defined by RCRA or to regulate coal ash as non-hazardous waste under RCRA. However, agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA were to designate coal ashdesignation as a hazardous waste, the agencywaste. 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 1211 and 2019 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, 2010,2011, of which approximately 5,000 were represented by unions. There are several bargaining units for the Company’s represented employees. In the 2010 third quarter, a new three-year agreement was ratified covering approximately 3,800 represented employees. The majority of the remaining represented employees are under contracts that expire in August 2012 and June 2011 and August 2012.October 2013.
Item 1A.Risk Factors |
There are various risks associated with the operations of DTE Energy’sEnergy'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’customers' rates. Our regulators also may decide to disallow recovery of certain costs in customers’customers' rates if they determine that those costs do not meet the standards for recovery under our governing laws and regulations. The StateOur 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 Michigan elected a new governor and legislature in November 2010 andcertain 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 whether the resulting changeswhat rates an MPSC order will adopt in political conditions will affect the regulations or interpretations affecting our utilities. future rate cases.New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increasesrates or require us to incur additional expenses.
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potential Customer Choice related migration. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be 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. 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. We have substantial amounts ofOur long term revolving credit facilities thatdo not expire in 2012until 2015, but we regularly access capital markets to refinance existing debt or fund new projects at our utilities, and 2013. We intend to seek to renew the facilities on or before the expiration dates. However, we cannot predict the outcome of these efforts, which could result in a decrease in amounts availableand/pricing or demand for those future transactions. an increase in our borrowing costs and negatively impact our financial performance.
Poor investment performance of pension and other postretirement benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations. Our costs of providing non-contributory defined benefit pension plans and other postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the debt and equity markets affects the value of assets that are held in trust to satisfy future obligations under our plans. We have significant benefit obligations and hold significant assets in trust to satisfy these obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in the foreseeable future. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase,
22
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.facilities and our gas distribution system. Many factors that could cause delaydelays 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.facilities and businesses.
Our non-utility businesses may not perform to our expectations. We rely on our non-utility operations for a resultportion of unforeseen maintenance,our earnings. If our current and contemplated non-utility investments do not perform at expected levels, we may be required to
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Our estimates of gas reserves are subject to change. While great care is exercised in utilizing historical information and assumptions to develop reasonable estimates of future production and cash flow, we cannot provide absolute assurance that our estimates of our Barnett gas reserves are accurate. We estimate proved gas reserves and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used.
Our ability to utilize production tax credits may be limited. To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels and electricity from alternative sources. We have generated production tax credits from coke production, landfill gas recovery;recovery, biomass fired electric generation, reduced emission fuel, renewable energy credits, steel industry fuel and gas production operations. All production tax credits
19
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.
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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.
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. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’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’sattorney's fees and expenses. On October 15, 2009, the U.S. District Court granted defendants’defendants' motions dismissing all of plaintiffs’plaintiffs' federal claims in the case on two
25
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’plaintiffs' state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.
In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV)NOV/FOV from the EPA alleging, among other things, that five of Detroit Edison’sEdison'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.
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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 NOV/FOV and the result of the civil action,two NOVs/FOVs, Detroit Edison could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs,and/or pay fines. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of this matter,these matters, or the timing of its resolution.
In October 2010, the Company received a Notice of Violation from the MDNREMichigan 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 thecontractor 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 JudgementJudgment that is designed to meet the effluent limitations and is in the process of optimizing plant performance to minimize any future excursions of the Ordinance and the General Pre-Treatment Standards. The DWSD has demanded payment of $176,000 in penalties in connection with the alleged violations. The Company is actively pursuing a settlement with DWSD, but we cannot predict the outcome or financial impact of this matter.
In April 2006, the prior ownersAugust 2011, Allegheny County Health Department (ACHD) issued an Enforcement Order alleging 114 incidents of fugitive pushing emissions at the coke battery facility in Pennsylvania thatand assessing a civil penalty of $114,000. The Company has appealed the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not
26
For additional discussion on legal matters, see Notes 1211 and 2019 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 | ||||||||||||||||
| Year | Quarter | High | Low | per Share | ||||||||||||
| 2010 | ||||||||||||||||
| First | $ | 45.93 | $ | 41.25 | $ | 0.530 | ||||||||||
| Second | $ | 49.05 | $ | 43.00 | $ | 0.530 | ||||||||||
| Third | $ | 49.06 | $ | 44.93 | $ | 0.560 | ||||||||||
| Fourth | $ | 47.66 | $ | 44.27 | $ | 0.560 | ||||||||||
| 2009 | ||||||||||||||||
| First | $ | 37.11 | $ | 23.32 | $ | 0.530 | ||||||||||
| Second | $ | 32.43 | $ | 27.32 | $ | 0.530 | ||||||||||
| Third | $ | 36.46 | $ | 30.59 | $ | 0.530 | ||||||||||
| Fourth | $ | 44.96 | $ | 33.75 | $ | 0.530 | ||||||||||
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, 2010,2011, there were 169,428,406169,247,282 shares of our common stock outstanding. These shares were held by a total of 74,82271,208 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 and $344 million in 2008.. The amount of future dividends will depend on our earnings, cash flows, financial condition and other factors that are periodically reviewed by our Board of Directors. Although there can be no assurances, we anticipate paying dividends for the foreseeable future.
See Note 1413 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 2221 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.
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See the following table for information as of December 31, 2010.2011.
| Number of Securities | Number of Securities | |||||||||||
| to be Issued Upon | Weighted-Average | Remaining Available for | ||||||||||
| Exercise of | Exercise Price of | Future Issuance Under Equity | ||||||||||
| Outstanding Options | Outstanding Options | Compensation Plans | ||||||||||
| Plans approved by shareholders | 4,827,457 | $ | 41.09 | 2,806,555 | ||||||||
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, 2010:2011:
| Number | ||||||||||||||||||||
| of Shares | Maximum Dollar | |||||||||||||||||||
| Purchased as | Value that May | |||||||||||||||||||
| Average | Part of Publicly | Yet Be | ||||||||||||||||||
| Number of | Price | Announced | Average | Purchased Under | ||||||||||||||||
| Shares | Paid per | Plans or | Price Paid | the Plans or | ||||||||||||||||
| Purchased(1) | Share(1) | Programs | per Share | Programs | ||||||||||||||||
| 01/01/10 — 01/31/10 | — | — | — | — | — | |||||||||||||||
| 02/01/10 — 02/28/10 | — | — | — | — | — | |||||||||||||||
| 03/01/10 — 03/31/10 | 55,000 | $ | 45.07 | — | — | — | ||||||||||||||
| 04/01/10 — 04/30/10 | — | — | — | — | — | |||||||||||||||
| 05/01/10 — 05/31/10 | 85,000 | 48.33 | — | — | — | |||||||||||||||
| 06/01/10 — 06/30/10 | — | — | — | — | — | |||||||||||||||
| 07/01/10 — 07/31/10 | — | — | — | — | — | |||||||||||||||
| 08/01/10 — 08/31/10 | 35,000 | 46.40 | — | — | — | |||||||||||||||
| 09/01/10 — 09/30/10 | 44,000 | 47.89 | — | — | — | |||||||||||||||
| 10/01/10 — 10/31/10 | — | — | — | — | — | |||||||||||||||
| 11/01/10 — 11/30/10 | 15,000 | 45.34 | — | — | — | |||||||||||||||
| 12/01/10 — 12/31/10 | — | — | — | — | — | |||||||||||||||
| Total | 234,000 | — | ||||||||||||||||||
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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24
COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN
Total Return To Shareholders
(Includes reinvestment of dividends)
| Annual Return Percentage | ||||||||||||||||||||
| Year Ended December 31 | ||||||||||||||||||||
| Company/Index | 2006 | 2007 | 2008 | 2009 | 2010 | |||||||||||||||
| DTE Energy Company | 17.66 | (5.03 | ) | (14.37 | ) | 30.08 | 9.06 | |||||||||||||
| S&P 500 Index | 15.79 | 5.49 | (37.00 | ) | 26.46 | 15.06 | ||||||||||||||
| S&P 500 Multi-Utilities Index | 16.74 | 10.86 | (24.34 | ) | 20.93 | 11.08 | ||||||||||||||
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 | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 | ||||||||||||||||||
| DTE Energy Company | 100 | 117.66 | 111.74 | 95.68 | 124.46 | 135.73 | ||||||||||||||||||
| S&P 500 Index | 100 | 115.79 | 122.16 | 76.96 | 97.33 | 111.99 | ||||||||||||||||||
| S&P 500 Multi-Utilities Index | 100 | 116.74 | 129.42 | 97.92 | 118.41 | 131.53 | ||||||||||||||||||
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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| Selected Financial Data |
The following selected financial data should be read in conjunction with the accompanying Management’s Discussion and Analysis in Item 7 of this Report and Notes to the Consolidated Financial Statements in Item 8 of this Report.
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
Operating Revenues | $ | 8,557 | $ | 8,014 | $ | 9,329 | $ | 8,475 | $ | 8,157 | ||||||||||
Net Income Attributable to DTE Energy Company | ||||||||||||||||||||
| Income from continuing operations(1) | $ | 630 | $ | 532 | $ | 526 | $ | 787 | $ | 389 | ||||||||||
| Discontinued operations | — | — | 20 | 184 | 43 | |||||||||||||||
| Cumulative effect of accounting changes | — | — | — | — | 1 | |||||||||||||||
| Net Income Attributable to DTE Energy Company | $ | 630 | $ | 532 | $ | 546 | $ | 971 | $ | 433 | ||||||||||
Diluted Earnings Per Common Share | ||||||||||||||||||||
| Income from continuing operations | $ | 3.74 | $ | 3.24 | $ | 3.22 | $ | 4.61 | $ | 2.18 | ||||||||||
| Discontinued operations | — | — | .12 | 1.08 | .24 | |||||||||||||||
| Cumulative effect of accounting changes | — | — | — | — | .01 | |||||||||||||||
| Diluted Earnings Per Common Share | $ | 3.74 | $ | 3.24 | $ | 3.34 | $ | 5.69 | $ | 2.43 | ||||||||||
Financial Information | ||||||||||||||||||||
| Dividends declared per share of common stock | $ | 2.18 | $ | 2.12 | $ | 2.12 | $ | 2.12 | $ | 2.075 | ||||||||||
| Total assets | $ | 24,896 | $ | 24,195 | $ | 24,590 | $ | 23,742 | $ | 23,785 | ||||||||||
| Long-term debt, including capital leases | $ | 7,089 | $ | 7,370 | $ | 7,741 | $ | 6,971 | $ | 7,474 | ||||||||||
| Shareholders’ equity | $ | 6,722 | $ | 6,278 | $ | 5,995 | $ | 5,853 | $ | 5,849 | ||||||||||
| 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) |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
EXECUTIVE OVERVIEW
DTE Energy is a diversified energy company with 20102011 operating revenues in excess of $8approximately $8.9 billion and approximately $25$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:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
| Net income attributable to DTE Energy Company | $ | 630 | $ | 532 | $ | 546 | ||||||
| Diluted earnings per common share | $ | 3.74 | $ | 3.24 | $ | 3.34 | ||||||
| 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. The decrease in Net income attributable to DTE Energy in 2009 from 2008 was primarily due to an $80 million after-tax gain recorded
Please see detailed explanations of segment performance in the Unconventional Gas Production segment on the 2008 salefollowing Results of Operations section.
DTE Energy's strategy is to achieve long-term earnings growth, a portion of Barnett shale properties, partially offset by higher earnings in the Electric Utility and Energy Trading segments.
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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 conservation of energy usage.
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
Uncollectible Expense | ||||||||||||
| Detroit Edison | $ | 58 | $ | 78 | $ | 87 | ||||||
| MichCon | 58 | 93 | 126 | |||||||||
| $ | 116 | $ | 171 | $ | 213 | |||||||
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.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 in the future. Expansionsegments.
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 these businesses will also result in our ability to further diversify geographically.
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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. For bothDetroit 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 weboth plan to seek regulatory approval in general rate case filings to include these capital expenditures within our regulatory rate base consistent with prior general rate case filing treatment. Detroit Edison is required to implementimplementing a20-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’sEdison's and the State of Michigan’sMichigan's sources of electric supply and addressing the state and national goals of increasing energy independence. Detroit Edison will seek separate regulatoryroutinely files renewable energy plans, requests for approval of renewable contracts and for recovery of these renewable capital expenditures within our regulatory rate base through ourwith the MPSC as the implementation of the 20-year renewable energy plan filings.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
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the establishment of an advanced metering infrastructure and other technologies that address improved electric distribution service. See Note 2 of the Notes to Consolidated Financial Statements.
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.
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27
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 renewableand/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.
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| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
Net Income Attributable to DTE Energy by Segment: | ||||||||||||
| Electric Utility | $ | 441 | $ | 376 | $ | 331 | ||||||
| Gas Utility | 127 | 80 | 85 | |||||||||
| Gas Storage and Pipelines | 51 | 49 | 38 | |||||||||
| Unconventional Gas Production(1) | (11 | ) | (9 | ) | 84 | |||||||
| Power and Industrial Projects | 85 | 31 | 40 | |||||||||
| Energy Trading | 6 | 75 | 42 | |||||||||
| Corporate & Other | (69 | ) | (70 | ) | (94 | ) | ||||||
| Discontinued Operations | — | — | 20 | |||||||||
| Net Income Attributable to DTE Energy Company | $ | 630 | $ | 532 | $ | 546 | ||||||
| 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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ELECTRIC UTILITY
Our Electric Utility segment consists principally of Detroit Edison.
Electric Utility results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 4,993 | $ | 4,714 | $ | 4,874 | ||||||
| Fuel and Purchased Power | 1,580 | 1,491 | 1,778 | |||||||||
| Gross Margin | 3,413 | 3,223 | 3,096 | |||||||||
| Operation and Maintenance | 1,305 | 1,277 | 1,322 | |||||||||
| Depreciation and Amortization | 849 | 844 | 743 | |||||||||
| Taxes Other Than Income | 237 | 205 | 232 | |||||||||
| Asset (Gains) Losses, Reserves and Impairments, Net | (6 | ) | (2 | ) | (1 | ) | ||||||
| Operating Income | 1,028 | 899 | 800 | |||||||||
| Other (Income) and Deductions | 317 | 295 | 283 | |||||||||
| Income Tax Provision | 270 | 228 | 186 | |||||||||
| Net Income Attributable to DTE Energy Company | $ | 441 | $ | 376 | $ | 331 | ||||||
| Operating Income as a Percent of Operating Revenues | 21 | % | 19 | % | 16 | % | ||||||
| 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 and increased $127 million in 2009.. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:
| 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 | |||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| Weather, net of RDM | $ | 84 | $ | (66 | ) | |||
| Energy optimization and renewable surcharge/regulatory offset | (10 | ) | 54 | |||||
| Securitization bond and tax surcharge rate increase | 40 | 62 | ||||||
| 2010 rate order, surcharges and other | 76 | 77 | ||||||
| Increase in gross margin | $ | 190 | $ | 127 | ||||
| 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 | |||||
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| 2010 | 2009 | 2008 | ||||||||||
| (In thousands of MWh) | ||||||||||||
Electric Sales | ||||||||||||
| Residential | 15,726 | 14,625 | 15,492 | |||||||||
| Commercial | 16,570 | 18,200 | 18,920 | |||||||||
| Industrial | 10,195 | 9,922 | 13,086 | |||||||||
| Other | 3,210 | 3,229 | 3,218 | |||||||||
| 45,701 | 45,976 | 50,716 | ||||||||||
| Interconnection sales(1) | 4,876 | 5,156 | 3,583 | |||||||||
| Total Electric Sales | 50,577 | 51,132 | 54,299 | |||||||||
Electric Deliveries | ||||||||||||
| Retail and Wholesale | 45,701 | 45,976 | 50,716 | |||||||||
| Electric Customer Choice, including self generators(2) | 5,005 | 1,477 | 1,457 | |||||||||
| Total Electric Sales and Deliveries | 50,706 | 47,453 | 52,173 | |||||||||
| (1) | Represents power that is not distributed by Detroit Edison. | |
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| 2010 | 2009 | 2008 | ||||||||||||||||||||||
| (In thousands of MWh) | ||||||||||||||||||||||||
Power Generated and Purchased | ||||||||||||||||||||||||
| Power Plant Generation | ||||||||||||||||||||||||
| Fossil | 39,433 | 73 | % | 40,595 | 74 | % | 41,254 | 71 | % | |||||||||||||||
| Nuclear | 7,738 | 14 | 7,406 | 14 | 9,613 | 17 | ||||||||||||||||||
| 47,171 | 87 | 48,001 | 88 | 50,867 | 88 | |||||||||||||||||||
| Purchased Power | 6,638 | 13 | 6,495 | 12 | 6,877 | 12 | ||||||||||||||||||
| System Output | 53,809 | 100 | % | 54,496 | 100 | % | 57,744 | 100 | % | |||||||||||||||
| Less Line Loss and Internal Use | (3,232 | ) | (3,364 | ) | (3,445 | ) | ||||||||||||||||||
| Net System Output | 50,577 | 51,132 | 54,299 | |||||||||||||||||||||
Average Unit Cost ($/MWh) | ||||||||||||||||||||||||
| Generation(1) | $ | 18.94 | $ | 18.20 | $ | 17.93 | ||||||||||||||||||
| Purchased Power | $ | 42.38 | $ | 37.74 | $ | 69.50 | ||||||||||||||||||
| Overall Average Unit Cost | $ | 21.83 | $ | 20.53 | $ | 24.07 | ||||||||||||||||||
| 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 maintenanceexpense increased $65 million in 2011 and increased $28 million in 2010 and decreased $45 million in 2009.. 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. The decrease
Depreciation and amortization expense decreased $31 million in 2009 was2011 due primarily due to $71 million from continuous improvement initiatives and other cost reductions resulting in lower contract labor and outside services expense, information technology and other staff expenses, $14 millionreduced amortization of lower employee benefit-related expenses, lower restoration and line clearance expenses of $12 million, $9 million of reduced uncollectible expenses and $6 million of reduced maintenance activities,regulatory assets, partially offset by expense related to higher pension and health care costs of $54 million and $14 million of energy optimization and renewable energy expenses.
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depreciable base. Depreciation and amortizationexpense increasedwas $5 million higher in 2010 and $101 million in 2009 due primarily to aexpense related to higher depreciable base and increased amortization of regulatory assets.
Taxes other than incomewere 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.
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GAS UTILITY
Our Gas Utility segment consists of MichCon and Citizens.
Gas Utility results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 1,648 | $ | 1,788 | $ | 2,152 | ||||||
| Cost of Gas | 870 | 1,057 | 1,378 | |||||||||
| Gross Margin | 778 | 731 | 774 | |||||||||
| Operation and Maintenance | 378 | 415 | 464 | |||||||||
| Depreciation and Amortization | 92 | 107 | 102 | |||||||||
| Taxes Other Than Income | 55 | 49 | 48 | |||||||||
| Asset (Gains) and Losses, Net | — | (18 | ) | (26 | ) | |||||||
| Operating Income | 253 | 178 | 186 | |||||||||
| Other (Income) and Deductions | 59 | 59 | 60 | |||||||||
| Income Tax Provision | 67 | 39 | 41 | |||||||||
| Net Income Attributable to DTE Energy Company | $ | 127 | $ | 80 | $ | 85 | ||||||
| Operating Income as a Percent of Operating Revenues | 15 | % | 10 | % | 9 | % | ||||||
| 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 and decreased $43 million in 2009.. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Consolidated Statement
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of Operations. The following table details changes in various gross margin components relative to the comparable prior period:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| 2010 self-implementation and rate order | $ | 125 | $ | — | ||||
| Lost and stolen gas | 13 | (15 | ) | |||||
| Midstream transportation and storage revenues | (20 | ) | 22 | |||||
| Uncollectible tracking mechanism | (43 | ) | (28 | ) | ||||
| Lower sales volumes | — | (13 | ) | |||||
| Weather | (23 | ) | (4 | ) | ||||
| Other | (5 | ) | (5 | ) | ||||
| Increase (decrease) in gross margin | $ | 47 | $ | (43 | ) | |||
| 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 | ||
Gas Markets (in Bcf) | ||||||||||||
| Gas sales | 118 | 137 | 148 | |||||||||
| End user transportation | 140 | 124 | 123 | |||||||||
| 258 | 261 | 271 | ||||||||||
| Intermediate transportation | 391 | 463 | 438 | |||||||||
| 649 | 724 | 709 | ||||||||||
| 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 maintenanceexpense 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 $49increased energy optimization expenses of $10 million, in 2009.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
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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 expensecontributions of $3 million for contributions to the Low Income Energy Efficiency Fund. The decrease in 2009 was primarily due to $33 million of reduced uncollectible expenses, $15 million of lower employee benefit-related expenses, $14 million from continuous improvement initiatives and other cost reductions resulting in lower contract labor and outside services expense, information technology and other staff expenses, partially offset by higher health care expenses of $8 million and $4 million of energy optimization expenses. See Note 12 of Notes to Consolidated Financial Statements in Item 8 of this report.
Outlook —We continue to move forward in our efforts to improveachieve operational excellence and sustained strong cash flows and earn our authorized return on equity. We plan to file a base rate case in the operating performancesecond quarter 2012 and cash flowexpect to self-implement new rates in the fourth quarter 2012 at the beginning of Gas Utility.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, we face additional issues,factors may impact earnings such as volatility in gas prices,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 an intense focus on our continuous improvement efforts to improve productivity, minimize lost and stolen gas, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.
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GAS STORAGE AND PIPELINES
Our Gas Storage and Pipelines segment consists of our non-utility gas pipelines and storage businesses.
Gas Storage and Pipelines results are discussed below:
| 2010 | 2009 | 2008 | |||||||||||||||||||||
| (In millions) | 2011 | 2010 | 2009 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Operating Revenues | $ | 83 | $ | 82 | $ | 71 | $ | 91 | $ | 83 | $ | 82 | |||||||||||
| Operation and Maintenance | 14 | 15 | 12 | 16 | 14 | 15 | |||||||||||||||||
| Depreciation and Amortization | 5 | 5 | 5 | 6 | 5 | 5 | |||||||||||||||||
| Taxes Other Than Income | 2 | 2 | 3 | 3 | 2 | 2 | |||||||||||||||||
| Asset (Gains) and Losses, Net | — | — | 1 | ||||||||||||||||||||
| Operating Income | 62 | 60 | 50 | 66 | 62 | 60 | |||||||||||||||||
| Other (Income) and Deductions | (25 | ) | (23 | ) | (12 | ) | (28 | ) | (25 | ) | (23 | ) | |||||||||||
| Income Tax Provision | 32 | 33 | 24 | ||||||||||||||||||||
| Income Tax Expense | 35 | 32 | 33 | ||||||||||||||||||||
| Net Income | 55 | 50 | 38 | 59 | 55 | 50 | |||||||||||||||||
| Noncontrolling interest | 4 | 1 | — | 2 | 4 | 1 | |||||||||||||||||
| Net Income Attributable to DTE Energy | $ | 51 | $ | 49 | $ | 38 | $ | 57 | $ | 51 | $ | 49 | |||||||||||
Net income attributable to DTE Energy increased $6 million and $2 million in 2011and $11 million in 2010 and 2009,, 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. The 2009 increase was driven by higher operating revenues resulting from increased capacity sold and higher rates from renewing storage contracts related to long-term agreements. In addition, in 2009 we had higher equity earnings from our investments in the Vector and Millennium Pipelines, reflecting a first full year of operations for Millennium.
Outlook —Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. 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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UNCONVENTIONAL GAS PRODUCTION
Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production within the Barnett shale in northern Texas. In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. We recognized a gain of $128 million ($80 million after-tax) on the sale in 2008.
Unconventional Gas Production results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 32 | $ | 31 | $ | 48 | ||||||
| Operation and Maintenance | 16 | 15 | 22 | |||||||||
| Depreciation, Depletion and Amortization | 15 | 16 | 12 | |||||||||
| Taxes Other Than Income | 2 | 1 | 1 | |||||||||
| Asset (Gains) and Losses, Net | 10 | 6 | (120 | ) | ||||||||
| Operating Income (Loss) | (11 | ) | (7 | ) | 133 | |||||||
| Other (Income) and Deductions | 6 | 6 | 2 | |||||||||
| Income Tax Provision (Benefit) | (6 | ) | (4 | ) | 47 | |||||||
| Net Income (Loss) Attributable to DTE Energy Company | $ | (11 | ) | $ | (9 | ) | $ | 84 | ||||
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| 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 | ) | ||
Outlook —In the longer-term, we We plan to continue to developfocus on optimizing the productivity of our holdings in the western portion of the Barnett shalewells and to seek opportunities for additional monetization of select properties when conditions are appropriate. Our strategy for 2011 isin 2012. The majority of our acreage position has rights to maintain our focus on reducing operating expenses and optimizing production volume. Givenshallow reserves lying above the current outlook of low natural gas prices,Barnett shale, specifically the Marble Falls formation. Recent drilling efforts will continuehave been largely successful in finding oil and high BTU gas. We anticipate the continued development of this liquids play which is expected to target liquids rich gas and oil production. During 2011, weadd value to our asset base. We expect total capital investment of $25$30 - 35 million to drill approximately 2030 new wells and continue to acquire select acreage and achieve production of approximately 6 - 7 Bcfe, of natural gas, compared with 5 Bcfe in 2010.2011. The majority of the drilling activity is expected to occur in the first half of 2012.
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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, servicesmarketing and marketing;trading services; and sell electricity from biomass-fired energy projects.
Power and Industrial Projects results are discussed below:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 1,144 | $ | 661 | $ | 987 | ||||||
| Operation and Maintenance | 978 | 593 | 899 | |||||||||
| Depreciation and Amortization | 60 | 40 | 34 | |||||||||
| Taxes other than Income | 14 | 9 | 12 | |||||||||
| Other Asset (Gains) and Losses, Reserves and Impairments, Net | (14 | ) | (6 | ) | 6 | |||||||
| Operating Income | 106 | 25 | 36 | |||||||||
| Other (Income) and Deductions | 13 | (1 | ) | (20 | ) | |||||||
| Income Taxes | ||||||||||||
| Provision | 36 | 5 | 18 | |||||||||
| Production Tax Credits | (33 | ) | (12 | ) | (7 | ) | ||||||
| 3 | (7 | ) | 11 | |||||||||
| Net Income | 90 | 33 | 45 | |||||||||
| Noncontrolling interest | 5 | 2 | 5 | |||||||||
| Net Income Attributable to DTE Energy Company | $ | 85 | $ | 31 | $ | 40 | ||||||
| 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 NotesNote 1 and 3 of Notes to the Consolidated Financial Statements, effective January 1, 2010, we adopted the provisions of ASU 2009-17, 2009-17,Amendments to FASB Interpretation 46(R). ASU2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, began consolidating five entities. Since these entities were previously accounted for under the equity method, the VIE consolidation had no impact on Net Income Attributable to DTE Energy. As a
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result of the consolidation of these VIEs, Operating Revenues and OperationsOperation 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,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 decreased $326pricing, and a $26 million increase in 2009.new on-site energy services projects. The 2010 increase is attributed primarily to $172 million of higher coke sales and a $156 million increase inon-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 2009 decrease2011 increase is due primarily to $111a $103 million reductionincrease in certain coal structured transactions, $176costs, 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 pricingvolumes primarily associated with the coal blending business and volumes of coal and emissions and $84$11 million of lower coke demand, partially offset by a $107 million increase in coal related services.
Asset (Gains) Losseswere higher 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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Other (income) and deductionswere 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 and lower by $19 million in 2009. The decreases in both years werewas 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 2011. Beginning in 2011, substantially2012. Substantially all of the metallurgical coke is under long-term contracts. The tax credits associated with our steel industry fuels facilities expired at December 31, 2010 that will result in lower tax credits of approximately $29 million in 2011. We supplyOur on-site energy services to the domestic automotive manufacturers who have also experienced stabilized demand for automobiles. Ouron-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 threefour facilities that will be in operation in 2012, we will convert and place intoare converting an additional facility to be placed in service two additional facilities in 2011 and 2013. We will continue to look for additional investment opportunities for waste-wood renewable power generation and other energy projects at favorable prices.
ENERGY TRADING
Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas
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pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillaryrelated 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:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 875 | $ | 804 | $ | 1,388 | ||||||
| Fuel, Purchased Power and Gas | 786 | 603 | 1,235 | |||||||||
| Gross Margin | 89 | 201 | 153 | |||||||||
| Operation and Maintenance | 59 | 71 | 68 | |||||||||
| Depreciation and Amortization | 5 | 5 | 5 | |||||||||
| Taxes Other Than Income | 2 | 3 | 2 | |||||||||
| Operating Income | 23 | 122 | 78 | |||||||||
| Other (Income) and Deductions | 12 | 10 | 5 | |||||||||
| Income Tax Provision (Benefit) | 5 | 37 | 31 | |||||||||
| Net Income Attributable to DTE Energy Company | $ | 6 | $ | 75 | $ | 42 | ||||||
| 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 and increased $48 million in 2009.2010. The overall decreaseincrease in gross margin in 20102011 was the result of lowerimproved economic performance, lower commodity prices, lower volatility in the markets we participate in and lower risk positions relative to 2009, coupled with the absence of prior year timing-related gains.timing losses. We experienced timing-related earnings volatility based on market movement related to derivative contracts.
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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.
Income tax provision increased $29 million in 2011, due to higher payroll and incentive costs and commissions, partially offset by lower contractor expense and allocated corporate costs.
pretax income. Income tax provisiontaxes decreased $32 million in 2010. This decrease is2010, due to lower pretax income, partially offset by $10 million of favorable tax-related adjustments in 2009 resulting from the settlement of federal income tax audits. Income taxes were higher by $6 million in 2009 due to higher pretax income, partially offset by the $10 million of favorable tax-related adjustments.
Outlook —In the near term, we expect market conditions to remain challenging and the profitability of this segment may be impacted by the volatility or lack thereof in commodity prices in the markets we participate in and the uncertainty of impacts associated with financial reform, regulatory changes and changes in operating rules of regional transmission organizations.
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The Energy Trading portfolio includes financial instruments, physical commodity contracts and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power transmission and generation capacity positions. Energy Trading also provides natural gas, power and ancillaryrelated 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.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 aremarked-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 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. The 2010 donation to the DTE Energy Foundation of $14 million was made by Detroit Edison and MichCon.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements
We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2011,2012, we expect that cash from operations will be $1.9 billion due to
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lower working capital requirements. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for existingnon-utility businesses in 20112012 of up to $1.4approximately $1.9 billion. The capital needs of our utilities will increase due primarily to environmental expenditures. We plan to seek regulatory approval to include theseutility capital expenditures withinin our regulatory rate base consistent with prior treatment. Capital spending for growth of
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existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
Cash and Cash Equivalents | ||||||||||||
| Cash Flow From (Used For) | ||||||||||||
| Operating activities: | ||||||||||||
| Net income | $ | 639 | $ | 535 | $ | 553 | ||||||
| Depreciation, depletion and amortization | 1,027 | 1,020 | 899 | |||||||||
| Deferred income taxes | 457 | 205 | 348 | |||||||||
| Gain on sale of non-utility business | — | — | (128 | ) | ||||||||
| Gain on sale of synfuel and other assets, net and synfuel impairment | (5 | ) | (10 | ) | (35 | ) | ||||||
| Working capital and other | (293 | ) | 69 | (78 | ) | |||||||
| 1,825 | 1,819 | 1,559 | ||||||||||
| Investing activities: | ||||||||||||
| Plant and equipment expenditures — utility | (1,011 | ) | (960 | ) | (1,183 | ) | ||||||
| Plant and equipment expenditures — non-utility | (88 | ) | (75 | ) | (190 | ) | ||||||
| Proceeds from sale of non-utility business | — | — | 253 | |||||||||
| Proceeds (refunds) from sale of synfuels and other assets | 56 | 83 | (278 | ) | ||||||||
| Restricted cash and other investments | (183 | ) | (112 | ) | (125 | ) | ||||||
| (1,226 | ) | (1,064 | ) | (1,523 | ) | |||||||
| Financing activities: | ||||||||||||
| Issuance of long-term debt | 614 | 427 | 1,310 | |||||||||
| Redemption of long-term debt | (663 | ) | (486 | ) | (446 | ) | ||||||
| Repurchase of long-term debt | — | — | (238 | ) | ||||||||
| Short-term borrowings, net | (177 | ) | (417 | ) | (340 | ) | ||||||
| Issuance of common stock | 36 | 35 | — | |||||||||
| Repurchase of common stock | — | — | (16 | ) | ||||||||
| Dividends on common stock and other | (396 | ) | (348 | ) | (354 | ) | ||||||
| (586 | ) | (789 | ) | (84 | ) | |||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | $ | 13 | $ | (34 | ) | $ | (48 | ) | ||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Cash and Cash Equivalents | |||||||||||
| Cash Flow From (Used For) | |||||||||||
| Operating activities: | |||||||||||
| Net income | $ | 720 | $ | 639 | $ | 535 | |||||
| Depreciation, depletion and amortization | 995 | 1,027 | 1,020 | ||||||||
| Deferred income taxes | 220 | 457 | 205 | ||||||||
| Asset (gains) and losses, reserves and impairments, net | (21 | ) | (5 | ) | (10 | ) | |||||
| Working capital and other | 94 | (293 | ) | 69 | |||||||
| 2,008 | 1,825 | 1,819 | |||||||||
| Investing activities: | |||||||||||
| Plant and equipment expenditures — utility | (1,382 | ) | (1,011 | ) | (960 | ) | |||||
| Plant and equipment expenditures — non-utility | (102 | ) | (88 | ) | (75 | ) | |||||
| Proceeds from sale of assets | 18 | 56 | 83 | ||||||||
| Restricted cash and other investments | (94 | ) | (183 | ) | (112 | ) | |||||
| (1,560 | ) | (1,226 | ) | (1,064 | ) | ||||||
| Financing activities: | |||||||||||
| Issuance of long-term debt | 1,179 | 614 | 427 | ||||||||
| Redemption of long-term debt | (1,455 | ) | (663 | ) | (486 | ) | |||||
| Short-term borrowings, net | 269 | (177 | ) | (417 | ) | ||||||
| Issuance of common stock | — | 36 | 35 | ||||||||
| Repurchase of common stock | (18 | ) | — | — | |||||||
| Dividends on common stock and other | (420 | ) | (396 | ) | (348 | ) | |||||
| (445 | ) | (586 | ) | (789 | ) | ||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | $ | 3 | $ | 13 | $ | (34 | ) | ||||
Cash from Operating Activities
A majority of our operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.
Cash from operations totaling $2 billion in 2011 was $183 million higher than the comparable 2010 period. The operating cash flow comparison primarily reflects cash generated from working capital items, partially offset by lower net income after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred income taxes and gains on sales of assets).
Cash from operations totaling $1.8 billion in 2010, was consistent with the comparable 2009 period. The operating cash flow comparison primarily reflects higher net income after adjusting for non-cash and non-operating items, (depreciation, depletion and amortization, deferred income taxes and gains on sales of assets), offset by highercash used for working capital requirements.items.
Cash from Investing Activities
Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated fromthe result of plant and equipment expenditures. In any given year, we will look to realize
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cash from under-performing or non-strategic assets or matured fully valued assets.
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Capital spending within the utility business is primarily to maintain and improve our electric generation and electric and gas distribution infrastructure and to comply with environmental regulations and gas pipeline replacements. renewable energy requirements.
Capital spending within our non-utility businesses is primarily for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.
Net cash used for investing activities was approximately $1.2 billionhigher in both 2011 and 2010 compared with net cash used for investing activities of $1.1 billion in 2009. The change wasdue primarily driven byto increased capital expenditures by our utility and non-utility businesses.
Cash from Financing Activities
We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by our operations.
Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50%50 percent to 52%,52 percent, to ensure it is consistent with our objective to have a strong investment grade debt rating.
Net cash used for financing activities was $445 million in 2011, compared to net cash used for financing activities of approximately $586 million for the same period in 2010. The change was primarily attributable to increased short-term borrowings and long-term debt issuances, partially offset by increased long-term debt redemptions.
Net cash used for financing activities was $586 million in 2010, compared to net cash used for financing activities of approximately $789 million for the same period in 2009. The change was primarily attributable to decreased payments for short-term borrowings. Increases in issuances of long-term debt were offset by increased long-term debt redemptions.
Outlook
We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and the non-utility businesses. We expect growth in our utilities to be driven primarily by new and existing state and federal regulations that will result in additional environmental and renewable energy investments which will increase the base from which rates are determined. Our non-utility growth is expected from additional investments primarily in energy projects as economic conditions improve.
our Gas Storage and Pipelines and Power and Industrial Projects segments.
We may be impacted by the delayed collection of underrecoveries of our various recovery and tracking mechanisms as a result of timing of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.
We have approximately $900$500 million in long-term debt maturing in the next twelve months. DTE Energy has $600 millionMost of unsecured debt maturing in June 2011 which is expected to be funded through a combination of internally generated funds and short- term debt. Substantially all of the remaining debtthese maturities relate to Securitization and other Detroit Edison issues. The repayment of the principal amount of the Securitization debt is
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funded through a surcharge payable by Detroit Edison’s electric customers. The repayment of the other Detroit Edison debt is expected to be refinanced with long-term debt.
In August 2010, DTE EnergyOctober 2011, the Company completed an early renewal of its $1.0 billion and its wholly owned subsidiaries, Detroit Edison and MichCon, entered into amended and restated two-year $1 billion$800 million syndicated unsecured revolving credit agreementsfacilities before their scheduled expiration in August 2012 and August 2013, respectively. The new three-year $800 million unsecured revolving credit agreements with a syndicate of 23 banks that may be used for general corporate borrowings, but are intended$1.8 billion five-year facility will expire in October 2016 and has covenants similar to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.25% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates.prior facilities. DTE Energy has approximately $1.7$1.4 billion of available liquidity at December 31, 2010.2011.
We expect to issue equity of approximately $300 million through our dividend reinvestment plan and pension and other employee benefit plans.
At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $240 million contribution to the pension plans in 2012. In March 2010,January 2012, the PPACA and the HCERA were enacted into law (collectively, the “Act”). The Act is a comprehensive health care reform bill. A provision of the PPACA repeals the current rule permitting deduction of the portion of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012. We have initiated changes in benefit design and delivery and are continuing to evaluate alternatives to minimize the impact of the legislation. WeCompany contributed $200$140 million to our pension plans duringits other postretirement benefit plans. At the year ended December 31, 2010, including a DTE Energy stock contributiondiscretion of $100 million in March 2010. We contributed $160 million to our postretirement medical and life insurance benefit plans duringmanagement, the year ended December 31, 2010, including a transfer of $25 million from the MichCon Grantor Trust. In January 2011, we contributed $200 million to our pension plans. Also, we contributed $81 million to our postretirement medical and life insurance plans in January 2011, and we expect to contributeCompany may make up to an additional $90$120 million throughout the remaindercontribution to its VEBA trusts in 2012.
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The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 provided for a special allowance for bonus depreciation in 2011 and 2012. Bonus depreciation is accelerated depreciation on certain types of business equipment that allows a tax deduction of either 50% or 100% of the cost of qualifying property in the year the asset is placed in service. DTE Energy expects to generate up to approximately $100$120 million to $200 million ofin cash in2011-2012from 2012 bonus depreciation deductions, a significant portion of which is expected to result from Detroit Edison property, plant and equipment expenditures during the qualifying period. The cash benefit is an acceleration of tax deductions that the Company would otherwise have received over 20 years.
We believe we have sufficient operating flexibility, cash resources and funding sources to maintain adequate amounts of liquidity and to meet our future operating cash and capital expenditure needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact earnings and cash flows.
See Notes 11, 12, 16, 18,15, 17, and 2120 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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Contractual Obligations
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2010:2011:
| 2016 | ||||||||||||||||||||
| Total | 2011 | 2012-2013 | 2014-2015 | and Beyond | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Long-term debt: | ||||||||||||||||||||
| Mortgage bonds, notes and other | $ | 6,888 | $ | 765 | $ | 691 | $ | 1,036 | $ | 4,396 | ||||||||||
| Securitization bonds | 793 | 150 | 341 | 302 | — | |||||||||||||||
| Trust preferred-linked securities | 289 | — | — | — | 289 | |||||||||||||||
| Capital lease obligations | 62 | 12 | 18 | 18 | 14 | |||||||||||||||
| Interest | 5,547 | 457 | 814 | 649 | 3,627 | |||||||||||||||
| Operating leases | 211 | 39 | 58 | 40 | 74 | |||||||||||||||
| Electric, gas, fuel, transportation and storage purchase obligations(1) | 5,921 | 2,175 | 1,670 | 744 | 1,332 | |||||||||||||||
| Other long-term obligations(2)(3)(4) | 243 | 49 | 44 | 31 | 119 | |||||||||||||||
| Total obligations | $ | 19,954 | $ | 3,647 | $ | 3,636 | $ | 2,820 | $ | 9,851 | ||||||||||
| Total | 2012 | 2013-2014 | 2015-2016 | 2017 and Beyond | |||||||||||||||
| (In millions) | |||||||||||||||||||
| Long-term debt: | |||||||||||||||||||
| Mortgage bonds, notes and other | $ | 6,770 | $ | 355 | $ | 1,329 | $ | 836 | $ | 4,250 | |||||||||
| Securitization bonds | 643 | 164 | 374 | 105 | — | ||||||||||||||
| Junior subordinated debentures | 280 | — | — | — | 280 | ||||||||||||||
| Capital lease obligations | 35 | 9 | 16 | 10 | — | ||||||||||||||
| Interest | 5,507 | 423 | 740 | 574 | 3,770 | ||||||||||||||
| Operating leases | 195 | 37 | 53 | 38 | 67 | ||||||||||||||
| Electric, gas, fuel, transportation and storage purchase obligations (1) | 5,080 | 2,112 | 1,920 | 333 | 715 | ||||||||||||||
| Other long-term obligations (2)(3)(4) | 235 | 164 | 33 | 13 | 25 | ||||||||||||||
| Total obligations | $ | 18,745 | $ | 3,264 | $ | 4,465 | $ | 1,909 | $ | 9,107 | |||||||||
| (1) | Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required. |
| (2) | Includes liabilities for unrecognized tax benefits of |
| (3) | Excludes other long-term liabilities of $184 million not directly derived from contracts or other agreements. |
| (4) | At December 31, |
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. The Company’s credit ratings affect our cost of capital and other terms of financing as well as our ability to access the credit and commercial paper markets. Management believes that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.
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As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the senior unsecured debt rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the senior unsecured debt rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if DTE Energy is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. A downgrade below investment grade could potentially increase the borrowing costs of DTE
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Energy and its subsidiaries and may limit access to the capital markets. The impact of a downgrade will not affect our ability to comply with our existing debt covenants. While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future credit rating agency reviews.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles require that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of these accounting policies can be found in the Notes to Consolidated Financial Statements in Item 8 of this Report.
Regulation
A significant portion of our business is subject to regulation. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.
In May 2011, Detroit Edison filed an application with the MPSC for approval of its initial pilot RDM reconciliation for the period February 2010 through January 2011 requesting authority to refund to customers approximately $56 million, plus interest. This amount was accrued by Detroit Edison at December 31, 2011. There are various interpretations and alternative calculation methodologies proposed by parties involved in the reconciliation proceeding relating to the pilot RDM refund calculation that could ultimately be adopted by the MPSC which may result in a range of customer refund amounts from $56 million to $140 million for this initial reconciliation filing under the pilot RDM.
In March 2010,addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the PPACApilot RDM effective October 2011 as ordered by the MPSC, and has requested a rehearing on this issue asserting that for reconciliation purposes, the pilot RDM should have been considered terminated in April 2011 when Detroit Edison self-implemented rates, consistent with prior MPSC orders. An April 2011 termination would result in a decrease to the liability. However, there can be no assurance that Detroit Edison will prevail in this matter. In addition, similar to the initial reconciliation case, there could be various interpretations and alternative calculation methodologies that could be adopted which may result in a range of refund obligations in excess of the amount accrued. Considering the rehearing request and alternative calculation methodologies, the potential customer refund amount could range from $10 million to $130 million for the second and final pilot RDM period.
The primary uncertainties involved in the calculation methodologies of the pilot RDM for both reconciliation periods include customer class groupings and treatment of fixed customer charges. The Company believes that the calculation methodology used and the HCERA were enacted into law (collectively,resulting refund estimates recorded follow the “Act”). A provisionrequirements and intent of the PPACA repealsMPSC orders and represent the current rule permitting deductionmost probable amount of the portionDetroit Edison's pilot RDM refund liability as of the drug coverage expense that is offset by the Medicare Part D subsidy, effective for taxable years beginning after December 31, 2012. This change in tax law required a remeasurement2011. An MPSC order
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on the deferred tax asset related to the Other Postretirement Benefit Obligation (OPEB) and the deferred tax liability related to the OPEB Regulatory Asset. Income tax accounting rules require the impact of a change in tax law be recognized in continuing operationsinitial filing is expected in the Consolidated Statementsfirst half of Operations in the period that the tax law change is enacted. However, regulated businesses may defer changes in tax law if allowed by regulators. The MPSC’s historical practice has been to recognize both the expense and working capital impacts for OPEB costs. In addition, the current and deferred tax effects related to OPEB costs have been recognized consistently. The effects of the subsidy have been reflected through lower tax expense included in rates. We believe we have reasonable assurance that the impacts related to the enactment of the Act are recoverable through rates in future periods. Therefore, the amounts related to2012. Detroit Edison is required to file an application with the MPSC for approval of $18 million and MichCon of $4 million have been deferred as Regulatory Assets.
its RDM reconciliation for the 2011 reconciliation period by May 2012. A newly designed RDM will be in effect beginning April 2012.
See Note 1211 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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Derivatives and Hedging Activities
Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. Substantially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets and liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. Management makes certain assumptions it believes that market participants would use in pricing assets and liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and our counterparties is incorporated in the valuation of the assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 20102011 and 2009.2010. Management believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. Actual cash returns realized on our derivatives may be different from the results we estimate using models. As fair value calculations are estimates based largely on commodity prices, we perform sensitivity analysis on the fair values of our forward contracts. See sensitivity analysis in Item 7A. Quantitative and Qualitative Disclosures About Market Risk. See also the Fair Value section, herein. See Notes 43 and 54 of the Notes to Consolidated Financial Statements in Item 8 of this report.Report.
Allowance for Doubtful Accounts
We establish an allowance for doubtful accounts based on historical losses and management’smanagement's assessment of existing economic conditions, customer trends, and other factors. The allowance for doubtful accounts for our two utilities is calculated using the aging approach that utilizes rates developed in reserve studies and applies these factors to past due receivable balances. As a result of the reduction in past due receivables in 2010,2011 and further refinements to our reserve studies, our allowance for doubtful accounts decreased significantly from the 20092010 balance. We believe the allowance for doubtful accounts is based on reasonable estimates. As part of the 2005 gas rate order for MichCon, the MPSC provided for the establishment of an uncollectible expense tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. The MPSC provided for a similar tracking mechanism for Detroit Edison in its rate order received January 2010. Detroit Edison filed for the suspension of the tracking mechanism2010, however it was terminated effective with the electric rate order in its pending rate case.October 2011.
Asset Impairments
Goodwill
Certain of our reporting units have goodwill or allocated goodwill resulting from purchase business combinations. We perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.
For Step 1 of the test, we estimate the reporting unit’sunit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require
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broad assumptions and significant judgment by management regarding future performance. We also employ market-based valuation techniques to test the reasonableness of the indications of value for the reporting units determined under the cash flow technique.
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We performed our annual impairment test as of October 1, 20102011 and determined that except for the Coal Services reporting unit, the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. The $4 million of goodwill attributable to the Coal Services reporting unit was written off in the fourth quarter of 2010 in connection with the sale of rail services assets. We also compared the aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to an acquisition control premium (the price in excess of a stock’sstock's market price that investors typically pay to gain control of an entity). The results of the test and key estimates that were incorporated are as follows.
As of October 1, 20102011 Valuation Date
| Fair Value | Discount | Terminal | ||||||||||||||||
| Reporting Unit | Goodwill | Reduction %(a) | Rate | Multiple(b) | Valuation Methodology(c) | |||||||||||||
| ($ in millions) | ||||||||||||||||||
| Electric Utility | $ | 1,206 | 26 | % | 7 | % | 8.0 | x | DCF, assuming stock sale | |||||||||
| Gas Utility | 759 | 7 | % | 7 | % | 9.5 | x | DCF, assuming stock sale | ||||||||||
| Energy Services | 28 | 66 | % | 13 | % | 9.0 | x | DCF, assuming asset sale(d) | ||||||||||
| Coal Services | 4 | (e) | n/a | 12 | % | 8.5 | x | DCF, assuming asset sale | ||||||||||
| Gas Storage and Pipelines | 8 | 66 | % | 10 | % | 8.0 | x | DCF, assuming asset sale | ||||||||||
| Energy Trading | 17 | 74 | % | 15 | % | n/a | Blended DCF, economic value of trading portfolio | |||||||||||
| Unconventional Gas Production | 2 | 62 | % | 13 | % | n/a | Blended DCF, transaction multiples | |||||||||||
| $ | 2,024 | |||||||||||||||||
| Reporting Unit | Goodwill | Fair Value Reduction % (a) | Discount Rate | Terminal Multiple (b) | Valuation Methodology (c) | ||||||||
| ($ in millions) | |||||||||||||
| Electric Utility | $ | 1,208 | 23 | % | 7 | % | 8.0x | DCF, assuming stock sale | |||||
| Gas Utility | 745 | 16 | % | 7 | % | 10.0x | DCF, assuming stock sale | ||||||
| Power and Industrial Projects | 26 | 71 | % | 10 | % | 8.0x | DCF, assuming asset sale (d) | ||||||
| Gas Storage and Pipelines | 22 | 75 | % | 9 | % | 10.0x | DCF, assuming asset sale | ||||||
| Energy Trading | 17 | 50 | % | 15 | % | n/a | Blended DCF, economic value of trading portfolio | ||||||
| Unconventional Gas Production | 2 | 55 | % | 11 | % | n/a | Blended DCF, transaction multiples | ||||||
| $ | 2,020 | ||||||||||||
| (a) | Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value, including goodwill. | |
| (b) | Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization | |
| (EBITDA). | ||
| (c) | Discounted cash flows (DCF) incorporated | |
| (d) | Asset sales were assumed except for | |
The Gas Utility reporting unit passed Step 1 of the impairment test, by a 7% margin. A substantive decreasehowever further declines in market multiples, negative regulatory actions or other disruptions in cash flows for the Gas Utility reporting unit could result in an impairment charge in the foreseeable future. For example, at the current discount rate and holding all other variables constant, a 0.5x1.5x decrease in the terminal multiple would lower the fair value by approximately $130$423 million. At the lower fair value, the Gas Utility reporting unit would likely fail Step 1 of the test potentially resulting in a charge for impairment of goodwill following completion of the Step 2 analysis.
We perform an annual impairment test each October. In between annual tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.
Long-Lived Assets
We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, condition of the asset, or plans to dispose of the asset before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. See Note 1110 of Notes to Consolidated Financial Statements in Item 8 of this Report.
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Pension and Postretirement Costs
We sponsor defined benefit pension plans and postretirement benefit plans for substantially all of theeligible employees of the Company. The measurement of the plan obligations and cost of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. When determining the various assumptions that are required, we consider historical information as well as future expectations. The benefit costs are affected by, among other things, the actual rate of return on plan assets, the long-term expected return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the anticipated rate of increase of health care costs and the level of benefits provided to employees and retirees. Pension and postretirement benefit costs attributed to the segments are included with labor costs and ultimately allocated to projects within the segments, some of which are capitalized.
We had pension costs for pension plans of $172 million in 2011, $112 million in 2010, and $58 million in 2009, and $24 million in 2008.2009. Postretirement benefits costs for all plans were $122 million in 2011, $164 million in 2010 and $205 million in 2009 and $142 million in 2008.2009. Pension and postretirement benefits costs for 20102011 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.5% for pension plan assets and 8.75%. for postretirement health and life plan assets. In developing our expected long-term rate of return assumptions, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity, bond and other markets. Our 20112012 expected long-term rate of return on pension plan assets is based on an asset allocation assumption utilizing active investment management of 47% in equity markets, 25% in fixed income markets, and 28% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we are lowering our long-term rate of return assumption for our pension plans to 8.50% for 2011. Our long-term rate of return assumption forand our postretirement health and life plans will remain at 8.75%to 8.25% for 2011.2012. We believe these two rates arethis rate is a reasonable assumptionsassumption for the long-term rate of return on our plan assets for 20112012 given our investment strategy. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.
We calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. Current accounting rules provide that the MRV of plan assets can be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For our pension plans, we use a calculated value when determining the MRV of the pension plan assets and recognize changes in fair value over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recognized. Financial markets in 20102011 contributed to our investment performance resulting in unrecognized net gains.losses. As of December 31, 2010,2011, we had $242$100 million of cumulative losses that remain to be recognized in the calculation of the MRV of pension assets. For our postretirement benefit plans, we use fair value when
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determining the MRV of postretirement benefit plan assets, therefore all investment losses and gains have been recognized in the calculation of MRV for these plans.
The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected pension plan and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis decreased to 5.0% at December 31, 2011 from 5.5% at December 31, 2010 from 5.9% at December 31, 2009.2010. We estimate that our 20112012 total pension costs will approximate $167$215 million compared to $112$172 million in 20102011 primarily due to a lower discount rate, lower expected return on assets and higher amortization of net actuarial losses, partially offset by better than expected asset returns in 2010 and 20112012 contributions. Our 20112012 postretirement benefit costs will approximate $137$155 million compared to $164$122 million in 20102011 primarily due to changing our strategy for providing post-65 prescription drug benefits to retirees, better than expected asset returns in 2010 and favorable retiree medical utilization. These positive impacts were partially offset by a lower discount rate, lower expected return on plan assets, higher amortization of net actuarial losses and updated assumed long-term retiree medical inflation.inflation, partially offset by favorable retiree medical utilization. Our health care trend rate assumes 7%7.00% for 20112012 through 2015, 6.5% in 2016, 6%6.50% in 2017, 5.5%6.00% in 2018, and 5%5.50% in 2019 and 5.00% in 2020 and beyond. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. The pension cost tracking mechanism that provided for recovery or refunding of pension costs above or below amounts reflected in Detroit Edison’s base rates, at the request of Detroit Edison, was not reauthorized by the MPSC in its rate order effective January 1, 2009. The MPSC approved the deferral of the non-capitalized portion of MichCon’sMichCon's negative pension expense. MichCon records a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.
Lowering the expected long-term rate of return on our plan assets by one percentage point would have increased our 20102011 pension costs by approximately $30$29 million. Lowering the discount rate and the salary increase assumptions by one percentage point would have increased our 20102011 pension costs by approximately $10$7 million. Lowering the health care cost trend assumptions by one percentage point would have decreased our postretirement benefit service and interest costs for 20102011 by approximately $25$24 million.
The value of our pension and postretirement benefit plan assets was $3.9 billion at December 31, 20102011 and $3.4 billion at December 31, 2009.2010. At December 31, 20102011, our pension plans were underfunded by $872 million$1.3 billion and our other postretirement benefit plans were underfunded by $1.3$1.5 billion. The 20102011 and 20092010 funding levels were generally similar due to positive investment performance returns and plan sponsor contributions
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in 20102011 and 2009,2010, largely offset by the decreased discount rates.
Pension and postretirement costs and pension cash funding requirements may increase in future years without typical returns in the financial markets. We made contributions to our pension plans of $200 million in each of 20102011 and 2009. Also, we contributed $200 million to our pension plans in January 2011.2010. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making contributions to our pension plans of $240 million in 2012 and up to $1.2$1.1 billion over the next five years. We made postretirement benefit plan contributions of $111 million and $160 million in 2011 and $205 million in 2010, and 2009, respectively. We are required by orders issued by the MPSC to make postretirement benefit contributions at least equal to the amounts included in Detroit Edison’s and MichCon’sour utilities' base rates. As a result, we contributed $81$140 million to our postretirement plans in January 20112012 and expect to make up to an additional $90$120 million contribution to our postretirement plans in 20112012 and, subject to MPSC funding requirements, up to $850$855 million over the next five years. The planned contributions will be made in cash, DTE Energy common stock or a combination of cash and stock.
Effective in June 2011, we discontinued offering future Greater Michigan represented employees a defined benefit pension plan benefit. In its place, the Company will annually contribute an amount equivalent to four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan. Also, for future Greater Michigan represented employees after completion of one year of service, in lieu of offering post-employment health care and life insurance benefits, the Company will contribute an amount equivalent to an additional four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan, plus a one-time contribution of $1,400.
Effective January 1, 2012, we discontinued offering future non-represented employees a cash balance retirement plan benefit. In its place, the Company will annually contribute an amount equivalent to four percent of an employee's eligible pay to the employee's defined contribution retirement savings plan. Also effective January 1, 2012, in lieu of offering future non-represented employees post-employment health care and life insurance benefits, the Company will allocate $4,000 per year to an account in a tax-exempt trust for each employee. The accumulated balance and earnings in an employee's account will vest when the employee has 10 years of service, regardless of age. These funds will be available to the employee to use for health care expenses after the employee leaves the Company.
See Note 2120 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Legal Reserves
We are involved in various legal proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against us.
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Insured and Uninsured Risks
Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage- $10 million, general liability- $7 million, workers’ compensation- $9 million, and autoliability-$7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2010,2011, this IBNR liability was approximately $39 million.
Accounting for Tax Obligations
We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We also have non-income tax obligations related to property, sales and use and employment-related taxes and ongoing appeals related to these tax matters.
Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess
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our ability to utilize tax attributes, including those in the form of carryforwards,carry-forwards, for which the benefits have already been reflected in the financial statements. We do not record valuation allowances for deferred tax assets related to capital losses that we believe will be realized in future periods. We believe the resulting tax reserve balances as of December 31, 20102011 and December 31, 20092010 are appropriately accounted. The ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material.
See Note 1312 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
FAIR VALUE
Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Contracts we typically classify as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items we do not generally account for as derivatives include natural gas inventory, power transmission, pipeline transportation and certain storage assets. See Notes 43 and 54 of the Notes to Consolidated Financial Statements.
The Company manages itsmark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).
55
The Company has established a fair value hierarchy whichthat prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). For further discussion of the fair value hierarchy, see Note 43 of the Notes to Consolidated Financial Statements.
The following tables provide details on changes in our MTM net asset (or liability) position during 2010:2011:
| Total | ||||
| (In millions) | ||||
| MTM at December 31, 2009 | $ | (93 | ) | |
| Reclassify to realized upon settlement | (3 | ) | ||
| Changes in fair value recorded to income | 123 | |||
| Amounts recorded to unrealized income | 120 | |||
| Changes in fair value recorded in regulatory liabilities | 6 | |||
| Amounts recorded in other comprehensive income pre-tax | 1 | |||
| Change in collateral held for others | (42 | ) | ||
| Option premiums paid (received) and other | (36 | ) | ||
| MTM at December 31, 2010 | $ | (44 | ) | |
| Total | |||
| (In millions) | |||
| MTM at December 31, 2010 | $ | (44 | ) |
| Reclassify to realized upon settlement | (37 | ) | |
| Changes in fair value recorded to income | 159 | ||
| Amounts recorded to unrealized income | 122 | ||
| Changes in fair value recorded in regulatory liabilities | 2 | ||
| Change in collateral held by others | 10 | ||
| Option premiums paid (received) and other | (41 | ) | |
| MTM at December 31, 2011 | $ | 49 | |
The table below shows the maturity of our MTM positions:
| 2014 | ||||||||||||||||||||
| and | Total Fair | |||||||||||||||||||
| Source of Fair Value | 2011 | 2012 | 2013 | Beyond | Value | |||||||||||||||
| (In millions) | ||||||||||||||||||||
| Level 1 | $ | 9 | $ | (23 | ) | $ | 11 | $ | 10 | $ | 7 | |||||||||
| Level 2 | (68 | ) | (54 | ) | (32 | ) | — | (154 | ) | |||||||||||
| Level 3 | 29 | 33 | (2 | ) | (1 | ) | 59 | |||||||||||||
| Total MTM before netting adjustments | $ | (30 | ) | $ | (44 | ) | $ | (23 | ) | $ | 9 | $ | (88 | ) | ||||||
| Collateral adjustments | $ | 44 | ||||||||||||||||||
| Total MTM at December 31, 2010 | $ | (44 | ) | |||||||||||||||||
| Source of Fair Value | 2012 | 2013 | 2014 | 2015 and Beyond | Total Fair Value | |||||||||||||||
| (In millions) | ||||||||||||||||||||
| Level 1 | $ | (32 | ) | $ | 17 | $ | 10 | $ | (5 | ) | $ | (10 | ) | |||||||
| Level 2 | (7 | ) | (34 | ) | 1 | — | (40 | ) | ||||||||||||
| Level 3 | 29 | 9 | 5 | 1 | 44 | |||||||||||||||
| Total MTM before collateral adjustments | $ | (10 | ) | $ | (8 | ) | $ | 16 | $ | (4 | ) | $ | (6 | ) | ||||||
| Collateral adjustments | $ | 55 | ||||||||||||||||||
| Total MTM at December 31, 2011 | $ | 49 | ||||||||||||||||||
45
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market Price Risk
DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.
The Electric and Gas utilityUtility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. However, the Company does not bear significant exposure to earnings risk as such changes are included in the form of PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas, storage sales revenue and uncollectible expenses at the Gas Utility. Gas Utility manages its market price risk related to storage sales revenue primarily through the sale of long-term storage contracts. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.
Our Gas Storage and Pipelines business segment has limited exposure to natural gas price fluctuations and manages its exposure through the sale of long-term storage and transportation contracts.
Our Unconventional Gas Production business segment has exposure to natural gas, natural gas liquids and crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we may use forward energy and futures contracts.
56
Our Power and Industrial Projects business segment is subject to electricity, natural gas, coal and coal-based product price risk and other risks associated with the weakened U.S. economy. To the extent that commodity price risk has not been mitigated through the use of long-term contracts, we manage this exposure using forward energy, capacity and futures contracts.
Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign currency exchange price fluctuations. These risks are managed by our energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.
Credit Risk
Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.
Other
MichCon has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in its last rate case. Detroit Edison had an uncollectible expense tracking mechanism which was terminated in Detroit Edison's October 2011 electric rate order. The Company hasuncollectible expense tracking mechanisms to mitigate a significant amount of losses related to uncollectible accounts receivable at Detroit Edison and MichCon. These mechanisms are subject torequire annual reconciliation proceedings before the jurisdiction of the MPSC and are periodically reviewed.MPSC. See Note 1211 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.
Trading Activities
We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internal credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of December 31, 2010:2011:
46
Credit Exposure Before Cash Collateral | Cash Collateral | Net Credit Exposure | |||||||||
| (In millions) | |||||||||||
| Investment Grade (1) | |||||||||||
| A− and Greater | $ | 171 | $ | — | $ | 171 | |||||
| BBB+ and BBB | 332 | — | 332 | ||||||||
| BBB− | 98 | — | 98 | ||||||||
| Total Investment Grade | 601 | — | 601 | ||||||||
| Non-investment grade (2) | 7 | — | 7 | ||||||||
| Internally Rated — investment grade (3) | 147 | — | 147 | ||||||||
| Internally Rated — non-investment grade (4) | 8 | — | 8 | ||||||||
| Total | $ | 763 | $ | — | $ | 763 | |||||
| Credit Exposure | ||||||||||||
| Before Cash | Cash | Net Credit | ||||||||||
| Collateral | Collateral | Exposure | ||||||||||
| (In millions) | ||||||||||||
| Investment Grade(1) | ||||||||||||
| A− and Greater | $ | 163 | $ | (10 | ) | $ | 153 | |||||
| BBB+ and BBB | 199 | — | 199 | |||||||||
| BBB− | 54 | — | 54 | |||||||||
| Total Investment Grade | 416 | (10 | ) | 406 | ||||||||
| Non-investment grade(2) | 2 | — | 2 | |||||||||
| Internally Rated — investment grade(3) | 147 | — | 147 | |||||||||
| Internally Rated — non-investment grade(4) | 12 | — | 12 | |||||||||
| Total | $ | 577 | $ | (10 | ) | $ | 567 | |||||
| (1) | This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five |
57
| largest counterparty exposures combined for this category represented approximately |
| (2) | This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented |
| (3) | This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately |
| (4) | This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately |
Interest Rate Risk
We are subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of December 31, 2010,2011, we had a floating ratedebt-to-total debt ratio of approximately two10 percent (excluding securitized debt).
Foreign Currency Exchange Risk
We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency exchange fluctuations, we have entered into a series of foreign currency exchange forward contracts through January 2013. Additionally, we may enter into fair value foreign currency exchange hedges to mitigate changes in the value of contracts or loans.July 2015.
Summary of Sensitivity Analysis
We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign currency exchange forward contracts. The commodity contracts and foreign currency exchange risk listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 20102011 and 20092010 by a hypothetical 10% and calculating the resulting change in the fair values.
47
The results of the sensitivity analysis calculations as of December 31, 20102011 and 2009:2010:
| Assuming a | Assuming a | |||||||||||||||||
| 10% Increase in Rates | 10% Decrease in Rates | |||||||||||||||||
| As of December 31, | As of December 31, | |||||||||||||||||
| Activity | 2010 | 2009 | 2010 | 2009 | Change in the Fair Value of | |||||||||||||
| (In millions) | ||||||||||||||||||
| Coal Contracts | $ | 1 | $ | — | $ | (1 | ) | $ | — | Commodity contracts | ||||||||
| Gas Contracts | $ | (11 | ) | $ | (2 | ) | $ | 10 | $ | 1 | Commodity contracts | |||||||
| Oil Contracts | $ | — | $ | 1 | $ | — | $ | (1 | ) | Commodity contracts | ||||||||
| Power Contracts | $ | (5 | ) | $ | (3 | ) | $ | 5 | $ | 2 | Commodity contracts | |||||||
| Interest Rate Risk | $ | (291 | ) | $ | (290 | ) | $ | 313 | $ | 313 | Long-term debt | |||||||
| Foreign Currency Exchange Risk | $ | 6 | $ | 2 | $ | 7 | $ | (2 | ) | Forward contracts | ||||||||
| Discount Rates | $ | — | $ | — | $ | — | $ | — | Commodity contracts | |||||||||
Assuming a 10% Increase in Rates | Assuming a 10% Decrease in Rates | ||||||||||||||||
| As of December 31, | As of December 31, | ||||||||||||||||
| Activity | 2011 | 2010 | 2011 | 2010 | Change in the Fair Value of | ||||||||||||
| (In millions) | |||||||||||||||||
| Coal Contracts | $ | (2 | ) | $ | 1 | $ | 2 | $ | (1 | ) | Commodity contracts | ||||||
| Gas Contracts | $ | (9 | ) | $ | (11 | ) | $ | 13 | $ | 10 | Commodity contracts | ||||||
| Power Contracts | $ | 4 | $ | (5 | ) | $ | (6 | ) | $ | 5 | Commodity contracts | ||||||
| Interest Rate Risk | $ | (260 | ) | $ | (291 | ) | $ | 276 | $ | 313 | Long-term debt | ||||||
| Foreign Currency Exchange Risk | $ | — | $ | 6 | $ | — | $ | 7 | Forward contracts | ||||||||
| Discount Rates | $ | — | $ | — | $ | — | $ | — | Commodity contracts | ||||||||
For further discussion of market risk, see Note 54 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
48
Item 8. | Financial Statements and Supplementary Data |
The following consolidated financial statements and financial statement schedule are included herein.
| Page | ||||
Financial Statement Schedule | ||||
59
49
Controls and Procedures
| (a) | Evaluation of disclosure controls and procedures |
Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange ActRules 13a-15(e) and15d-15(e)) as of December 31, 2010,2011, which is the end of the period covered by this report. Based on this evaluation, the Company’s CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.
| (b) | Management’s report on internal control over financial reporting |
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange ActRules 13a-15(f) and15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of the Company has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010.2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.Based on this assessment, management concluded that, as of December 31, 2010,2011, the Company’s internal control over financial reporting was effective based on those criteria.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 20102011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm who also audited the Company’s financial statements, as stated in their report which appears herein.
| (c) | Changes in internal control over financial reporting |
There have been no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 20102011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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50
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of DTE Energy Company and its subsidiaries at December 31, 20102011 and 2009,2010, and the results of their operations and their cash flows for each of the three years thenin the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the years ended December 31, 2010 and 2009 listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010,2011, based on criteria established inInternal Control —- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’sCompany's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sManagement's report on internal control over financial reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’sCompany's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’scompany's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’scompany's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’scompany's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan
February 18, 201116, 2012
62
| Year Ended December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
Operating Revenues | $ | 8,557 | $ | 8,014 | $ | 9,329 | ||||||
Operating Expenses | ||||||||||||
| Fuel, purchased power and gas | 3,190 | 3,118 | 4,306 | |||||||||
| Operation and maintenance | 2,578 | 2,372 | 2,694 | |||||||||
| Depreciation, depletion and amortization | 1,027 | 1,020 | 901 | |||||||||
| Taxes other than income | 308 | 275 | 304 | |||||||||
| Gain on sale of non-utility business | — | — | (128 | ) | ||||||||
| Other asset (gains) and losses, reserves and impairments, net | (10 | ) | (20 | ) | (11 | ) | ||||||
| 7,093 | 6,765 | 8,066 | ||||||||||
Operating Income | 1,464 | 1,249 | 1,263 | |||||||||
Other (Income) and Deductions | ||||||||||||
| Interest expense | 549 | 545 | 503 | |||||||||
| Interest income | (12 | ) | (19 | ) | (19 | ) | ||||||
| Other income | (78 | ) | (102 | ) | (104 | ) | ||||||
| Other expenses | 55 | 43 | 64 | |||||||||
| 514 | 467 | 444 | ||||||||||
Income Before Income Taxes | 950 | 782 | 819 | |||||||||
Income Tax Provision | 311 | 247 | 288 | |||||||||
Income from Continuing Operations | 639 | 535 | 531 | |||||||||
Discontinued Operations Income, net of tax | — | — | 22 | |||||||||
Net Income | 639 | 535 | 553 | |||||||||
Less: Net Income Attributable to Noncontrolling Interests From | ||||||||||||
| Continuing operations | 9 | 3 | 5 | |||||||||
| Discontinued operations | — | — | 2 | |||||||||
| 9 | 3 | 7 | ||||||||||
Net Income Attributable to DTE Energy Company | $ | 630 | $ | 532 | $ | 546 | ||||||
Basic Earnings per Common Share | ||||||||||||
| Income from continuing operations | $ | 3.75 | $ | 3.24 | $ | 3.22 | ||||||
| Discontinued operations | — | — | .12 | |||||||||
| Total | $ | 3.75 | $ | 3.24 | $ | 3.34 | ||||||
Diluted Earnings per Common Share | ||||||||||||
| Income from continuing operations | $ | 3.74 | $ | 3.24 | $ | 3.22 | ||||||
| Discontinued operations | — | — | .12 | |||||||||
| Total | $ | 3.74 | $ | 3.24 | $ | 3.34 | ||||||
Weighted Average Common Shares Outstanding | ||||||||||||
| Basic | 168 | 164 | 163 | |||||||||
| Diluted | 169 | 164 | 163 | |||||||||
Dividends Declared per Common Share | $ | 2.18 | $ | 2.12 | $ | 2.12 | ||||||
| Year Ended December 31 | |||||||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions, except per share amounts) | |||||||||||
| Operating Revenues | $ | 8,897 | $ | 8,557 | $ | 8,014 | |||||
| Operating Expenses | |||||||||||
| Fuel, purchased power and gas | 3,537 | 3,190 | 3,118 | ||||||||
| Operation and maintenance | 2,628 | 2,578 | 2,372 | ||||||||
| Depreciation, depletion and amortization | 995 | 1,027 | 1,020 | ||||||||
| Taxes other than income | 313 | 308 | 275 | ||||||||
| Asset (gains) and losses, reserves and impairments, net | 1 | (10 | ) | (20 | ) | ||||||
| 7,474 | 7,093 | 6,765 | |||||||||
| Operating Income | 1,423 | 1,464 | 1,249 | ||||||||
| Other (Income) and Deductions | |||||||||||
| Interest expense | 494 | 549 | 545 | ||||||||
| Interest income | (10 | ) | (12 | ) | (19 | ) | |||||
| Other income | (117 | ) | (78 | ) | (102 | ) | |||||
| Other expenses | 69 | 55 | 43 | ||||||||
| 436 | 514 | 467 | |||||||||
| Income Before Income Taxes | 987 | 950 | 782 | ||||||||
| Income Tax Expense | 267 | 311 | 247 | ||||||||
| Net Income | 720 | 639 | 535 | ||||||||
| Less Net Income Attributable to Noncontrolling Interests | 9 | 9 | 3 | ||||||||
| Net Income Attributable to DTE Energy Company | $ | 711 | $ | 630 | $ | 532 | |||||
| Basic Earnings per Common Share | |||||||||||
| Net Income Attributable to DTE Energy Company | $ | 4.19 | $ | 3.75 | $ | 3.24 | |||||
| Diluted Earnings per Common Share | |||||||||||
| Net Income Attributable to DTE Energy Company | $ | 4.18 | $ | 3.74 | $ | 3.24 | |||||
| Weighted Average Common Shares Outstanding | |||||||||||
| Basic | 169 | 168 | 164 | ||||||||
| Diluted | 170 | 169 | 164 | ||||||||
| Dividends Declared per Common Share | $ | 2.32 | $ | 2.18 | $ | 2.12 | |||||
See Notes to Consolidated Financial Statements
52
DTE Energy Company
| December 31 | ||||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
| Cash and cash equivalents | $ | 65 | $ | 52 | ||||
| Restricted cash (Note 2) | 120 | 84 | ||||||
| Accounts receivable (less allowance for doubtful accounts of $196 and $262, respectively) | ||||||||
| Customer | 1,393 | 1,438 | ||||||
| Other | 402 | 217 | ||||||
| Inventories | ||||||||
| Fuel and gas | 460 | 309 | ||||||
| Materials and supplies | 202 | 200 | ||||||
| Deferred income taxes | 139 | 167 | ||||||
| Derivative assets | 131 | 209 | ||||||
| Other | 255 | 201 | ||||||
| 3,167 | 2,877 | |||||||
Investments | ||||||||
| Nuclear decommissioning trust funds | 939 | 817 | ||||||
| Other | 518 | 598 | ||||||
| 1,457 | 1,415 | |||||||
Property | ||||||||
| Property, plant and equipment | 21,574 | 20,588 | ||||||
| Less accumulated depreciation, depletion and amortization | (8,582 | ) | (8,157 | ) | ||||
| 12,992 | 12,431 | |||||||
Other Assets | ||||||||
| Goodwill | 2,020 | 2,024 | ||||||
| Regulatory assets | 4,058 | 4,110 | ||||||
| Securitized regulatory assets | 729 | 870 | ||||||
| Intangible assets | 67 | 54 | ||||||
| Notes receivable | 123 | 113 | ||||||
| Derivative assets | 77 | 116 | ||||||
| Other | 206 | 185 | ||||||
| 7,280 | 7,472 | |||||||
Total Assets | $ | 24,896 | $ | 24,195 | ||||
| December 31 | |||||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| ASSETS | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 68 | $ | 65 | |||
| Restricted cash, principally Securitization | 147 | 120 | |||||
| Accounts receivable (less allowance for doubtful accounts of $162 and $196, respectively) | |||||||
| Customer | 1,317 | 1,351 | |||||
| Other | 90 | 402 | |||||
| Inventories | |||||||
| Fuel and gas | 572 | 460 | |||||
| Materials and supplies | 219 | 202 | |||||
| Deferred income taxes | 51 | 139 | |||||
| Derivative assets | 222 | 131 | |||||
| Regulatory assets | 314 | 100 | |||||
| Other | 196 | 197 | |||||
| 3,196 | 3,167 | ||||||
| Investments | |||||||
| Nuclear decommissioning trust funds | 937 | 939 | |||||
| Other | 525 | 518 | |||||
| 1,462 | 1,457 | ||||||
| Property | |||||||
| Property, plant and equipment | 22,541 | 21,574 | |||||
| Less accumulated depreciation, depletion and amortization | (8,795 | ) | (8,582 | ) | |||
| 13,746 | 12,992 | ||||||
| Other Assets | |||||||
| Goodwill | 2,020 | 2,020 | |||||
| Regulatory assets | 4,539 | 4,058 | |||||
| Securitized regulatory assets | 577 | 729 | |||||
| Intangible assets | 73 | 67 | |||||
| Notes receivable | 123 | 123 | |||||
| Derivative assets | 74 | 77 | |||||
| Other | 199 | 206 | |||||
| 7,605 | 7,280 | ||||||
| Total Assets | $ | 26,009 | $ | 24,896 | |||
See Notes to Consolidated Financial Statements
64
53
DTE Energy Company
Consolidated Statements of Financial Position — (Continued)
| December 31 | ||||||||
| 2010 | 2009 | |||||||
| (In millions, except shares) | ||||||||
LIABILITIES AND EQUITY | ||||||||
Current Liabilities | ||||||||
| Accounts payable | $ | 729 | $ | 723 | ||||
| Accrued interest | 111 | 114 | ||||||
| Dividends payable | 95 | 88 | ||||||
| Short-term borrowings | 150 | 327 | ||||||
| Current portion long-term debt, including capital leases | 925 | 671 | ||||||
| Derivative liabilities | 142 | 220 | ||||||
| Other | 597 | 502 | ||||||
| 2,749 | 2,645 | |||||||
Long-Term Debt (net of current portion) | ||||||||
| Mortgage bonds, notes and other | 6,114 | 6,237 | ||||||
| Securitization bonds | 643 | 793 | ||||||
| Trust preferred-linked securities | 289 | 289 | ||||||
| Capital lease obligations | 43 | 51 | ||||||
| 7,089 | 7,370 | |||||||
Other Liabilities | ||||||||
| Deferred income taxes | 2,632 | 2,096 | ||||||
| Regulatory liabilities | 1,328 | 1,337 | ||||||
| Asset retirement obligations | 1,498 | 1,420 | ||||||
| Unamortized investment tax credit | 75 | 85 | ||||||
| Derivative liabilities | 110 | 198 | ||||||
| Liabilities from transportation and storage contracts | 83 | 96 | ||||||
| Accrued pension liability | 866 | 881 | ||||||
| Accrued postretirement liability | 1,275 | 1,287 | ||||||
| Nuclear decommissioning | 149 | 136 | ||||||
| Other | 275 | 328 | ||||||
| 8,291 | 7,864 | |||||||
Commitments and Contingencies (Notes 12 and 20) | ||||||||
Equity | ||||||||
| Common stock, without par value, 400,000,000 shares authorized, 169,428,406 and 165,400,045 shares issued and outstanding, respectively | 3,440 | 3,257 | ||||||
| Retained earnings | 3,431 | 3,168 | ||||||
| Accumulated other comprehensive loss | (149 | ) | (147 | ) | ||||
Total DTE Energy Company Shareholders’ Equity | 6,722 | 6,278 | ||||||
| Noncontrolling interests | 45 | 38 | ||||||
Total Equity | 6,767 | 6,316 | ||||||
Total Liabilities and Equity | $ | 24,896 | $ | 24,195 | ||||
| December 31 | |||||||
| 2011 | 2010 | ||||||
| (In millions, except shares) | |||||||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities | |||||||
| Accounts payable | $ | 782 | $ | 729 | |||
| Accrued interest | 95 | 111 | |||||
| Dividends payable | 99 | 95 | |||||
| Short-term borrowings | 419 | 150 | |||||
| Current portion long-term debt, including capital leases | 526 | 925 | |||||
| Derivative liabilities | 158 | 142 | |||||
| Other | 549 | 597 | |||||
| 2,628 | 2,749 | ||||||
| Long-Term Debt (net of current portion) | |||||||
| Mortgage bonds, notes and other | 6,405 | 6,114 | |||||
| Securitization bonds | 479 | 643 | |||||
| Junior subordinated debentures | 280 | — | |||||
| Trust preferred-linked securities | — | 289 | |||||
| Capital lease obligations | 23 | 43 | |||||
| 7,187 | 7,089 | ||||||
| Other Liabilities | |||||||
| Deferred income taxes | 3,116 | 2,632 | |||||
| Regulatory liabilities | 1,019 | 1,328 | |||||
| Asset retirement obligations | 1,591 | 1,498 | |||||
| Unamortized investment tax credit | 65 | 75 | |||||
| Derivative liabilities | 89 | 110 | |||||
| Accrued pension liability | 1,298 | 866 | |||||
| Accrued postretirement liability | 1,484 | 1,275 | |||||
| Nuclear decommissioning | 148 | 149 | |||||
| Other | 331 | 358 | |||||
| 9,141 | 8,291 | ||||||
| Commitments and Contingencies (Notes 11 and 19) | |||||||
| Equity | |||||||
| Common stock, without par value, 400,000,000 shares authorized, 169,247,282 and 169,428,406 shares issued and outstanding, respectively | 3,417 | 3,440 | |||||
| Retained earnings | 3,750 | 3,431 | |||||
| Accumulated other comprehensive loss | (158 | ) | (149 | ) | |||
| Total DTE Energy Company Equity | 7,009 | 6,722 | |||||
| Noncontrolling interests | 44 | 45 | |||||
| Total Equity | 7,053 | 6,767 | |||||
| Total Liabilities and Equity | $ | 26,009 | $ | 24,896 | |||
See Notes to Consolidated Financial Statements
65
54
DTEEnergy Company
| Year Ended December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
Operating Activities | ||||||||||||
| Net income | $ | 639 | $ | 535 | $ | 553 | ||||||
| Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
| Depreciation, depletion and amortization | 1,027 | 1,020 | 899 | |||||||||
| Deferred income taxes | 457 | 205 | 348 | |||||||||
| Gain on sale of non-utility business | — | — | (128 | ) | ||||||||
| Other asset (gains), losses and reserves, net | (5 | ) | (10 | ) | (4 | ) | ||||||
| Gain on sale of interests in synfuel projects | — | — | (31 | ) | ||||||||
| Contributions from synfuel partners | — | — | 14 | |||||||||
| Changes in assets and liabilities, exclusive of changes shown separately (Note 23) | (293 | ) | 69 | (92 | ) | |||||||
| Net cash from operating activities | 1,825 | 1,819 | 1,559 | |||||||||
Investing Activities | ||||||||||||
| Plant and equipment expenditures — utility | (1,011 | ) | (960 | ) | (1,183 | ) | ||||||
| Plant and equipment expenditures — non-utility | (88 | ) | (75 | ) | (190 | ) | ||||||
| Proceeds from sale of interests in synfuel projects | — | — | 84 | |||||||||
| Refunds to synfuel partners | — | — | (387 | ) | ||||||||
| Proceeds from sale of non-utility business | — | — | 253 | |||||||||
| Proceeds from sale of other assets, net | 56 | 83 | 25 | |||||||||
| Restricted cash for debt redemption | (32 | ) | 2 | 54 | ||||||||
| Proceeds from sale of nuclear decommissioning trust fund assets | 377 | 295 | 232 | |||||||||
| Investment in nuclear decommissioning trust funds | (410 | ) | (315 | ) | (255 | ) | ||||||
| Consolidation of VIEs | 19 | — | — | |||||||||
| Investment in Millennium Pipeline Project | (49 | ) | (15 | ) | (31 | ) | ||||||
| Other investments | (88 | ) | (79 | ) | (125 | ) | ||||||
| Net cash used for investing activities | (1,226 | ) | (1,064 | ) | (1,523 | ) | ||||||
Financing Activities | ||||||||||||
| Issuance of long-term debt | 614 | 427 | 1,310 | |||||||||
| Redemption of long-term debt | (663 | ) | (486 | ) | (446 | ) | ||||||
| Repurchase of long-term debt | — | — | (238 | ) | ||||||||
| Short-term borrowings, net | (177 | ) | (417 | ) | (340 | ) | ||||||
| Issuance of common stock | 36 | 35 | — | |||||||||
| Repurchase of common stock | — | — | (16 | ) | ||||||||
| Dividends on common stock | (360 | ) | (348 | ) | (344 | ) | ||||||
| Other | (36 | ) | — | (10 | ) | |||||||
| Net cash used for financing activities | (586 | ) | (789 | ) | (84 | ) | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 13 | (34 | ) | (48 | ) | |||||||
Cash and Cash Equivalents Reclassified from Assets Held for Sale | — | — | 11 | |||||||||
Cash and Cash Equivalents at Beginning of Period | 52 | 86 | 123 | |||||||||
Cash and Cash Equivalents at End of Period | $ | 65 | $ | 52 | $ | 86 | ||||||
| Year Ended December 31 | |||||||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Operating Activities | |||||||||||
| Net income | $ | 720 | $ | 639 | $ | 535 | |||||
| Adjustments to reconcile net income to net cash from operating activities: | |||||||||||
| Depreciation, depletion and amortization | 995 | 1,027 | 1,020 | ||||||||
| Deferred income taxes | 220 | 457 | 205 | ||||||||
| Asset (gains) and losses, reserves and impairments, net | (21 | ) | (5 | ) | (10 | ) | |||||
| Changes in assets and liabilities, exclusive of changes shown separately (Note 22) | 94 | (293 | ) | 69 | |||||||
| Net cash from operating activities | 2,008 | 1,825 | 1,819 | ||||||||
| Investing Activities | |||||||||||
| Plant and equipment expenditures — utility | (1,382 | ) | (1,011 | ) | (960 | ) | |||||
| Plant and equipment expenditures — non-utility | (102 | ) | (88 | ) | (75 | ) | |||||
| Proceeds from sale of assets | 18 | 56 | 83 | ||||||||
| Restricted cash for debt redemption, principally Securitization | (5 | ) | (32 | ) | 2 | ||||||
| Proceeds from sale of nuclear decommissioning trust fund assets | 80 | 377 | 295 | ||||||||
| Investment in nuclear decommissioning trust funds | (97 | ) | (410 | ) | (315 | ) | |||||
| Consolidation of VIEs | — | 19 | — | ||||||||
| Investment in Millennium Pipeline Project | (3 | ) | (49 | ) | (15 | ) | |||||
| Other | (69 | ) | (88 | ) | (79 | ) | |||||
| Net cash used for investing activities | (1,560 | ) | (1,226 | ) | (1,064 | ) | |||||
| Financing Activities | |||||||||||
| Issuance of long-term debt | 1,179 | 614 | 427 | ||||||||
| Redemption of long-term debt | (1,455 | ) | (663 | ) | (486 | ) | |||||
| Short-term borrowings, net | 269 | (177 | ) | (417 | ) | ||||||
| Issuance of common stock | — | 36 | 35 | ||||||||
| Repurchase of common stock | (18 | ) | — | — | |||||||
| Dividends on common stock | (389 | ) | (360 | ) | (348 | ) | |||||
| Other | (31 | ) | (36 | ) | — | ||||||
| Net cash used for financing activities | (445 | ) | (586 | ) | (789 | ) | |||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 3 | 13 | (34 | ) | |||||||
| Cash and Cash Equivalents at Beginning of Period | 65 | 52 | 86 | ||||||||
| Cash and Cash Equivalents at End of Period | $ | 68 | $ | 65 | $ | 52 | |||||
See Notes to Consolidated Financial Statements
66
55
DTE Energy Company
| Accumulated | ||||||||||||||||||||||||
| Other | Non- | |||||||||||||||||||||||
| Common Stock | Retained | Comprehensive | Controlling | |||||||||||||||||||||
| Shares | Amount | Earnings | Loss | Interest | Total | |||||||||||||||||||
| (Dollars in millions, shares in thousands) | ||||||||||||||||||||||||
| Balance, December 31, 2007 | 163,232 | $ | 3,176 | $ | 2,790 | $ | (113 | ) | $ | 48 | $ | 5,901 | ||||||||||||
| Net income (loss) | — | — | 546 | — | 7 | 553 | ||||||||||||||||||
| Implementation of ASC 820, net of tax | — | — | 4 | — | — | 4 | ||||||||||||||||||
| Implementation of ASC 715 measurement date provision, net of tax | — | — | (9 | ) | — | — | (9 | ) | ||||||||||||||||
| Dividends declared on common stock | — | — | (346 | ) | — | — | (346 | ) | ||||||||||||||||
| Repurchase and retirement of common stock | (479 | ) | (16 | ) | — | — | — | (16 | ) | |||||||||||||||
| Benefit obligations, net of tax | — | — | — | (22 | ) | — | (22 | ) | ||||||||||||||||
| Foreign currency translation, net of tax | — | — | — | (2 | ) | — | (2 | ) | ||||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 6 | — | 6 | ||||||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | (34 | ) | — | (34 | ) | ||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | 14 | 14 | ||||||||||||||||||
| Stock-based compensation, distributions to noncontrolling interests and other | 267 | 15 | — | — | (26 | ) | (11 | ) | ||||||||||||||||
| Balance, December 31, 2008 | 163,020 | 3,175 | 2,985 | (165 | ) | 43 | 6,038 | |||||||||||||||||
| Net income | — | — | 532 | — | 3 | 535 | ||||||||||||||||||
| Dividends declared on common stock | — | — | (349 | ) | — | — | (349 | ) | ||||||||||||||||
| Issuance of common stock | 1,109 | 35 | — | — | — | 35 | ||||||||||||||||||
| Benefit obligations, net of tax | — | — | — | 7 | — | 7 | ||||||||||||||||||
| Foreign currency translation, net of tax | — | — | — | 2 | — | 2 | ||||||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 1 | — | 1 | ||||||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | 8 | — | 8 | ||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | 4 | 4 | ||||||||||||||||||
| Stock-based compensation, distributions to noncontrolling interests and other | 1,271 | 47 | — | — | (12 | ) | 35 | |||||||||||||||||
| Balance, December 31, 2009 | 165,400 | 3,257 | 3,168 | (147 | ) | 38 | 6,316 | |||||||||||||||||
| Net income | — | — | 630 | — | 9 | 639 | ||||||||||||||||||
| Dividends declared on common stock | — | — | (367 | ) | — | — | (367 | ) | ||||||||||||||||
| Issuance of common stock | 777 | 36 | — | — | — | 36 | ||||||||||||||||||
| Contribution of common stock to pension plan | 2,224 | 100 | — | — | — | 100 | ||||||||||||||||||
| Benefit obligations, net of tax | — | — | — | 15 | — | 15 | ||||||||||||||||||
| Foreign currency translation, net of tax | — | — | — | 1 | — | 1 | ||||||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 2 | — | 2 | ||||||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | (20 | ) | — | (20 | ) | ||||||||||||||||
| Stock-based compensation, distributions to noncontrolling interests and other | 1,027 | 47 | — | — | (2 | ) | 45 | |||||||||||||||||
Balance, December 31, 2010 | 169,428 | $ | 3,440 | $ | 3,431 | $ | (149 | ) | $ | 45 | $ | 6,767 | ||||||||||||
Accumulated Other Comprehensive Loss | Non-Controlling Interest | |||||||||||||||||||||
| Common Stock | Retained Earnings | |||||||||||||||||||||
| Shares | Amount | Total | ||||||||||||||||||||
| (Dollars in millions, shares in thousands) | ||||||||||||||||||||||
| Balance, December 31, 2008 | 163,020 | $ | 3,175 | $ | 2,985 | $ | (165 | ) | $ | 43 | $ | 6,038 | ||||||||||
| Net income | — | — | 532 | — | 3 | 535 | ||||||||||||||||
| Dividends declared on common stock | — | — | (349 | ) | — | — | (349 | ) | ||||||||||||||
| Issuance of common stock | 1,109 | 35 | — | — | — | 35 | ||||||||||||||||
| Benefit obligations, net of tax | — | — | — | 7 | — | 7 | ||||||||||||||||
| Foreign currency translation, net of tax | — | — | — | 2 | — | 2 | ||||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 1 | — | 1 | ||||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | 8 | — | 8 | ||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | 4 | 4 | ||||||||||||||||
| Stock-based compensation, distributions to noncontrolling interests and other | 1,271 | 47 | — | — | (12 | ) | 35 | |||||||||||||||
| Balance, December 31, 2009 | 165,400 | $ | 3,257 | $ | 3,168 | $ | (147 | ) | $ | 38 | $ | 6,316 | ||||||||||
| Net income | — | — | 630 | — | 9 | 639 | ||||||||||||||||
| Dividends declared on common stock | — | — | (367 | ) | — | — | (367 | ) | ||||||||||||||
| Issuance of common stock | 777 | 36 | — | — | — | 36 | ||||||||||||||||
| Contribution of common stock to pension plan | 2,224 | 100 | — | — | — | 100 | ||||||||||||||||
| Benefit obligations, net of tax | — | — | — | 15 | — | 15 | ||||||||||||||||
| Foreign currency translation, net of tax | — | — | — | 1 | — | 1 | ||||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 2 | — | 2 | ||||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | (20 | ) | — | (20 | ) | ||||||||||||||
| Stock-based compensation, distributions to noncontrolling interests and other | 1,027 | 47 | — | — | (2 | ) | 45 | |||||||||||||||
| Balance, December 31, 2010 | 169,428 | $ | 3,440 | $ | 3,431 | $ | (149 | ) | $ | 45 | $ | 6,767 | ||||||||||
| Net Income | — | — | 711 | — | 9 | 720 | ||||||||||||||||
| Dividends declared on common stock | — | — | (392 | ) | — | — | (392 | ) | ||||||||||||||
| Repurchase of common stock | (1,184 | ) | (58 | ) | — | — | — | (58 | ) | |||||||||||||
| Benefit obligations, net of tax | — | — | — | (9 | ) | — | (9 | ) | ||||||||||||||
| Stock-based compensation, distributions to noncontrolling interests and other | 1,003 | 35 | — | — | (10 | ) | 25 | |||||||||||||||
| Balance, December 31, 2011 | 169,247 | $ | 3,417 | $ | 3,750 | $ | (158 | ) | $ | 44 | $ | 7,053 | ||||||||||
See Notes to Consolidated Financial Statements
56
DTE Energy Company
The following table displays comprehensive income:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Net income | $ | 639 | $ | 535 | $ | 553 | ||||||
| Other comprehensive income (loss), net of tax: | ||||||||||||
| Benefit obligations: | ||||||||||||
| Benefit obligations, net of taxes of $3, $4 and $(12) | 5 | 7 | (22 | ) | ||||||||
| Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $5, $ — and $ — | 10 | — | — | |||||||||
| 15 | 7 | (22 | ) | |||||||||
| Net unrealized gains on derivatives: | ||||||||||||
| Gains arising during the period, net of taxes of $1, $2 and $2 | 1 | 3 | 4 | |||||||||
| Amounts reclassified to income, net of taxes of $1, $(1) and $1 | 1 | (2 | ) | 2 | ||||||||
| 2 | 1 | 6 | ||||||||||
| Net unrealized gains (losses) on investments: | ||||||||||||
| Gains (losses) arising during the period, net of taxes of $(6), $3 and $(19) | (10 | ) | 5 | (34 | ) | |||||||
| Amounts reclassified to income, net of taxes of $ —, $2 and $ — | — | 3 | — | |||||||||
| Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $(5), $ — and $ — | (10 | ) | — | — | ||||||||
| (20 | ) | 8 | (34 | ) | ||||||||
| Foreign currency translation, net of taxes of $ —, $1 and $(1) | 1 | 2 | (2 | ) | ||||||||
| Comprehensive income | 637 | 553 | 501 | |||||||||
| Less: Comprehensive income attributable to noncontrolling interests | 9 | 3 | 7 | |||||||||
| Comprehensive income attributable to DTE Energy Company | $ | 628 | $ | 550 | $ | 494 | ||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Net income | $ | 720 | $ | 639 | $ | 535 | |||||
| Other comprehensive income (loss), net of tax: | |||||||||||
| Benefit obligations: | |||||||||||
| Benefit obligations, net of taxes of $(5), $3 and $4 | (9 | ) | 5 | 7 | |||||||
| Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $—, $5 and $— | — | 10 | — | ||||||||
| (9 | ) | 15 | 7 | ||||||||
| Net unrealized gains on derivatives: | |||||||||||
| Gains during the period, net of taxes of $—, $1 and $2 | — | 1 | 3 | ||||||||
| Amounts reclassified to income, net of taxes of $—, $1 and $(1) | — | 1 | (2 | ) | |||||||
| — | 2 | 1 | |||||||||
| Net unrealized gains (losses) on investments: | |||||||||||
| Gains (losses) during the period, net of taxes of $—, $(6) and $3 | — | (10 | ) | 5 | |||||||
| Amounts reclassified to income, net of taxes of $—, $— and $2 | — | — | 3 | ||||||||
| Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $—, $(5) and $— | — | (10 | ) | — | |||||||
| — | (20 | ) | 8 | ||||||||
| Foreign currency translation, net of taxes of $—, $— and $1 | — | 1 | 2 | ||||||||
| Comprehensive income | 711 | 637 | 553 | ||||||||
| Less comprehensive income attributable to noncontrolling interests | 9 | 9 | 3 | ||||||||
| Comprehensive income attributable to DTE Energy Company | $ | 702 | $ | 628 | $ | 550 | |||||
See Notes to Consolidated Financial Statements
57
DTE Energy Company
Notes to Consolidated Financial Statements
| NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION |
Corporate Structure
DTE Energy owns the following businesses:
Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan;
MichCon, a natural gas utility 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; and Other businesses involved in 1) natural gas pipelines, gathering and storage; 2) unconventional gas and oil project development and production; 3) power and industrial projects; and 4) energy marketing and trading operations. |
Detroit Edison and MichCon are regulated by the MPSC. Certain activities of Detroit Edison and MichCon, as well as various other aspects of businesses under DTE Energy are regulated by the FERC. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDNRE.
MDEQ.
References in this reportReport to “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
Basis of Presentation
The accompanying Consolidated Financial Statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require management to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from the Company’s estimates.
Certain prior year balances were reclassified to match the current year’s financial statement presentation.
Principles of Consolidation
The Company consolidates all majority owned subsidiaries and investments in entities in which it has controlling influence. Non-majority owned investments are accounted for using the equity method when the Company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When the Company does not influence the operating policies of an investee, the cost method is used. These consolidated financial statements also reflect the Company’s proportionate interests in certain jointly owned utility plant. The Company eliminates all intercompany balances and transactions.
Effective January 1, 2010, the Company adopted the provisions of ASU 2009-17, 2009-17,Amendments to FASB Interpretation 46(R). ASU2009-17 changed the methodology for determining the primary beneficiary of a VIE from a quantitative risk and rewards-based model to a qualitative determination. There is no grandfathering of previous consolidation conclusions. As a result, the Company re-evaluated all prior VIE and primary beneficiary determinations. The requirements of ASU2009-17 were adopted on a prospective basis.
The Company evaluates whether an entity is a VIE whenever reconsideration events occur. The Company consolidates VIEs for which it is the primary beneficiary. If the Company is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of accounting. When assessing the determination of the primary beneficiary, the Company considers all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb the expected lossesand/or the right to receive the expected
69
returns of the VIE. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.
Legal entities within the Company’s Power and Industrial Projects segmentssegment enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are generally designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk. These entities generally are VIEs. The Company re-evaluated prior VIE and primary beneficiary determinations and, as a result, in 2010 began consolidating five entities that were previously accounted for as equity investments. The primary reason for the change in the primary beneficiary conclusion was the determination that the Company’s responsibility for the management and operations of the VIEs afforded the Company the power to direct the significant activities of the VIEs. In addition, the Company has interests in certain VIEs that we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.
58
The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of December 31, 2010,2011, the carrying amount of assets and liabilities in the Consolidated Statement of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.
In 2001, Detroit Edison financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly-owned special purpose entity, Securitization. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. Under ASU2009-17, thisThis entity is now a VIE, and continues to beis consolidated asby the Company is the primary beneficiary.
Company.
DTE Energy hashad interests in various unconsolidated trusts that were formed for the purpose of issuing preferred securities and lending the gross proceeds to the Company. The assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments the Company makes are used by the trusts to make cash distributions on the preferred securities it has issued. DTE Energy has reviewed these interests and has determined they arewere VIEs, but the Company iswas not the primary beneficiary as it doesdid not have variable interests in the trusts and therefore, the trusts arewere not consolidated by the Company.
See Note 15.
The maximum risk exposure for consolidated VIEs is reflected on the Company’s Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally limited to its investment and amounts which it has guaranteed.
70
The following table summarizes the major balance sheet items for consolidated VIEs as of December 31, 2011and December 31, 2010 and . Amounts at December 31, 2009. Amounts at December 31, 20102011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. Entities,VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below.
| December 31, 2010 | ||||||||||||||||||||
| Restricted | December 31, | |||||||||||||||||||
| Securitization | Other | Total | Amounts | 2009 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
| Cash and cash equivalents | $ | — | $ | 4 | $ | 4 | $ | — | $ | 2 | ||||||||||
| Restricted cash | 104 | 8 | 112 | 112 | — | |||||||||||||||
| Accounts receivable | 42 | 8 | 50 | 44 | 4 | |||||||||||||||
| Inventories | — | 99 | 99 | — | 9 | |||||||||||||||
| Other current assets | — | 1 | 1 | — | — | |||||||||||||||
| Property, plant and equipment | — | 54 | 54 | 38 | 45 | |||||||||||||||
| Securitized regulatory assets | 729 | — | 729 | 729 | — | |||||||||||||||
| Other assets | 13 | 9 | 22 | 21 | 9 | |||||||||||||||
| $ | 888 | $ | 183 | $ | 1,071 | $ | 944 | $ | 69 | |||||||||||
| LIABILITIES | ||||||||||||||||||||
| Accounts payable and accrued current liabilities | $ | 17 | $ | 27 | $ | 44 | $ | 18 | $ | 3 | ||||||||||
| Current portion long-term debt, including capital leases | 150 | 7 | 157 | 157 | 4 | |||||||||||||||
| Other current liabilities | 62 | 6 | 68 | 66 | 1 | |||||||||||||||
| Mortgage bonds, notes and other | — | 35 | 35 | 35 | 17 | |||||||||||||||
| Securitization bonds | 643 | — | 643 | 643 | — | |||||||||||||||
| Capital lease obligations | — | 23 | 23 | 23 | 26 | |||||||||||||||
| Other long term liabilities | 6 | 7 | 13 | 12 | — | |||||||||||||||
| $ | 878 | $ | 105 | $ | 983 | $ | 954 | $ | 51 | |||||||||||
| December 31, 2011 | ||||||||||||||||
| Securitization | Other | Total | Restricted Amounts | |||||||||||||
| (In millions) | ||||||||||||||||
| ASSETS | ||||||||||||||||
| Cash and cash equivalents | $ | — | $ | 25 | $ | 25 | $ | — | ||||||||
| Restricted cash | 107 | 7 | 114 | 114 | ||||||||||||
| Accounts receivable | 34 | 17 | 51 | 36 | ||||||||||||
| Inventories | — | 183 | 183 | — | ||||||||||||
| Other current assets | — | 1 | 1 | — | ||||||||||||
| Property, plant and equipment | — | 73 | 73 | 23 | ||||||||||||
| Securitized regulatory assets | 577 | — | 577 | 577 | ||||||||||||
| Other assets | 10 | 6 | 16 | 16 | ||||||||||||
| $ | 728 | $ | 312 | $ | 1,040 | $ | 766 | |||||||||
| LIABILITIES | ||||||||||||||||
| Accounts payable and accrued current liabilities | $ | 14 | $ | 24 | $ | 38 | $ | 14 | ||||||||
| Current portion long-term debt, including capital leases | 164 | 7 | 171 | 171 | ||||||||||||
| Other current liabilities | 55 | — | 55 | 55 | ||||||||||||
| Mortgage bonds, notes and other | — | 30 | 30 | 30 | ||||||||||||
| Securitization bonds | 479 | — | 479 | 479 | ||||||||||||
| Capital lease obligations | — | 14 | 14 | 14 | ||||||||||||
| Other long term liabilities | 7 | 2 | 9 | 8 | ||||||||||||
| $ | 719 | $ | 77 | $ | 796 | $ | 771 | |||||||||
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| December 31, 2010 | ||||||||||||||||
| Securitization | Other | Total | Restricted Amounts | |||||||||||||
| (In millions) | ||||||||||||||||
| ASSETS | ||||||||||||||||
| Cash and cash equivalents | $ | — | $ | 4 | $ | 4 | $ | — | ||||||||
| Restricted cash | 104 | 8 | 112 | 112 | ||||||||||||
| Accounts receivable | 42 | 8 | 50 | 44 | ||||||||||||
| Inventories | — | 99 | 99 | — | ||||||||||||
| Other current assets | — | 1 | 1 | — | ||||||||||||
| Property, plant and equipment | — | 54 | 54 | 38 | ||||||||||||
| Securitized regulatory assets | 729 | — | 729 | 729 | ||||||||||||
| Other assets | 13 | 9 | 22 | 21 | ||||||||||||
| $ | 888 | $ | 183 | $ | 1,071 | $ | 944 | |||||||||
| LIABILITIES | ||||||||||||||||
| Accounts payable and accrued current liabilities | $ | 17 | $ | 27 | $ | 44 | $ | 18 | ||||||||
| Current portion long-term debt, including capital leases | 150 | 7 | 157 | 157 | ||||||||||||
| Other current liabilities | 62 | 6 | 68 | 66 | ||||||||||||
| Mortgage bonds, notes and other | — | 35 | 35 | 35 | ||||||||||||
| Securitization bonds | 643 | — | 643 | 643 | ||||||||||||
| Capital lease obligations | — | 23 | 23 | 23 | ||||||||||||
| Other long term liabilities | 6 | 7 | 13 | 12 | ||||||||||||
| $ | 878 | $ | 105 | $ | 983 | $ | 954 | |||||||||
Amounts for non-consolidated VIEs as of December 31, 2011 and December 31, 2010 and December 31, 2009 are as follows:
| December 31, | December 31, | |||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| Other investments | $ | 98 | $ | 178 | ||||
| Note receivable and bank loan guarantee | 6 | 11 | ||||||
| Trust preferred — linked securities | 289 | 289 | ||||||
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December 31, 2011 | December 31, 2010 | ||||||
| (In millions) | |||||||
| Other investments | $ | 117 | $ | 98 | |||
| Notes receivable | 7 | 6 | |||||
| Trust preferred — linked securities | — | 289 | |||||
NOTE 2 — (Continued)SIGNIFICANT ACCOUNTING POLICIES
Revenues
Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electricelectricity and gas provided but unbilled at the end of each month. Rates for Detroit Edison and MichCon include provisions to adjust billings for fluctuations in fuel and purchased power costs, cost of natural gas and certain other costs. Revenues are adjusted for differences between actual costs and the amounts billed in current rates. Under or over recovered revenues related to these cost trackingrecovery mechanisms are recorded on the Consolidated Statement of Financial Position and are recovered or returned to customers through adjustments to the billing factors. See Note 12 for further discussion of cost recovery mechanisms.
Detroit Edison hashad a CIM, which iswas an over/under recovery mechanism that measuresmeasured non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales. If annual electric Customer Choice sales exceedexceeded the baseline amount from Detroit Edison’sEdison's most recent rate case, 90 percent of its lost non-fuel revenues associated with sales above that level may be recovered from full service customers. If annual electric Customer Choice sales decreasedecreased below the baseline, the Company must refund 90 percent of its increase in non-fuel revenues associated with sales below that level to full service customers. The CIM
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was terminated effective with the October 20, 2011 MPSC rate order. On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2011.
Detroit Edison and MichCon havehad RDMs that arein place in 2011 designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas. The January 2010 MPSC order in Detroit Edison’s 2009 rate case provided for, among other items, the implementation of a pilot electric RDM effective February 1, 2010. The electric RDM enablesenabled Detroit Edison to recover or refund the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established in the MPSC order. The 2011 pilot RDM established in Detroit Edison's 2009 rate case was terminated by the MPSC in October 2011, but the Company has requested rehearing on this point asserting the termination should have occurred in April 2011. Detroit Edison will have a newly designed RDM that will be effective in April 2012. See Note 11 for further discussion of the newly designed RDM. The June 2010 MPSC order in MichCon’sMichCon's 2009 rate case provided for among other items, the implementation of a pilot gas RDM effective July 1, 2010. The gas RDM2010, which enables MichCon to recover or refund the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base average sales per customer established in the MPSC order. The RDMs for Detroit Edison and MichCon addressgas RDM is subject to review in future MPSC proceedings during the pilot program. The gas RDM addresses changes in customer usage due to general economic conditions and conservation, but do not shield the utilities from the impacts of lost customers. In addition, the pilot electric RDM materially shields Detroit Edison from the impact of weather on customer usage. The pilot gas RDM does not shield MichCon from the impactimpacts of lost customers or weather on customer usage. The electric and gas RDMs are subject to reviewvariations.
See Note 11 for further discussion of recovery mechanisms authorized by the MPSC after the initial one-year pilot programs.
MPSC.
Non-utility businesses recognize revenues as services are provided and products are delivered. Revenues and energy costs related to trading contracts are presented on a net basis in the Consolidated Statements of Operations. Commodity derivatives used for trading purposes are accounted for using themark-to-market method with unrealized gains and losses recorded in Operating Revenues.
Accounting for ISO Transactions
Detroit Edison participates in the energy market through MISO. MISO requires that we submit hourly day-ahead, real time and FTR bids and offers for energy at locations across the MISO region. Detroit Edison accounts for MISO transactions on a net hourly basis in each of the day-ahead, real-time and FTR markets and net transactions across all MISO energy market locations. In any single hour Detroit Edison records net purchases in Fuel, purchased power and gas and net sales in Operating revenues on the Consolidated Statements of Operations. Detroit Edison records net sale billing adjustments when invoices are received. Detroit Edison records expense accruals for future net purchases adjustments based on historical experience, and reconciles accruals to actual expenses when invoices are received from MISO.
Energy Trading participates in the energy markets through various independent system operators and regional transmission organizations.organizations (ISOs and RTOs). These markets require that we submit hourly day-ahead, real time bids and offers for
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energy at locations across each region. We submit bids in the annual and monthly auction revenue rights and FTR auctions to the regional transmission organizations. Energy Trading accounts for these transactions on a net hourly basis for the day-ahead, real-time and FTR markets. These transactions are related to our trading contracts which are presented on a net basis in Operating revenues in the Consolidated Statements of Income.
Detroit Edison and Energy Trading record expense accruals for future net purchases adjustments based on historical experience, and reconcile accruals to actual expenses when invoices are received from MISO, the ISOs and RTOs.
Comprehensive Income
Comprehensive income is the change in Commoncommon shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following table, amounts recorded to accumulated other comprehensive loss for the year ended December 31, 20102011 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, the Company’s interest in comprehensive income of equity investees, and changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, and foreign currency translation adjustments.
| Net | Net | Accumulated | ||||||||||||||||||
| Unrealized | Unrealized | Foreign | Other | |||||||||||||||||
| Gain/(Loss) | Gain/(Loss) | Benefit | Currency | Comprehensive | ||||||||||||||||
| on Derivatives | on Investments | Obligations | Translation | Loss | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Beginning balances | $ | (6 | ) | $ | (10 | ) | $ | (131 | ) | $ | — | $ | (147 | ) | ||||||
| Current period change, net of tax | 2 | (20 | ) | 15 | 1 | (2 | ) | |||||||||||||
| Ending balance | $ | (4 | ) | $ | (30 | ) | $ | (116 | ) | $ | 1 | $ | (149 | ) | ||||||
Net Unrealized Gain/(Loss) on Derivatives | Net Unrealized Gain/(Loss) on Investments | Benefit Obligations | Foreign Currency Translation | Accumulated Other Comprehensive Loss | |||||||||||||||
| (In millions) | |||||||||||||||||||
| Beginning balances | $ | (4 | ) | $ | (30 | ) | $ | (116 | ) | $ | 1 | $ | (149 | ) | |||||
| Current period change, net of tax | — | — | (9 | ) | — | (9 | ) | ||||||||||||
| Ending balance | $ | (4 | ) | $ | (30 | ) | $ | (125 | ) | $ | 1 | $ | (158 | ) | |||||
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Cash Equivalents and Restricted Cash
Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt, primarily Securitization bonds, and partnership operating agreements. Restricted cash designated for interest and principal payments within one year is classified as a current asset.
Receivables
Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value.
The allowance for doubtful accounts for Detroit Edison and MichCon is generally calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the due date, which is typically in 21 days, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on past-due terms with customers. Customer accounts are written off when collection efforts have been exhausted, generally one year after service has been terminated.
The customer allowance for doubtful accounts for our other businesses is calculated based on specific review of probable future collections based on receivable balances in excess of 9030 days.
Unbilled revenues of $575$597 million and $618$575 million are included in customer accounts receivable at December 31, 20102011 and 2009,2010, respectively.
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Notes Receivable
Notes receivable, or financing receivables, are primarily comprised of capital lease receivables and loans and are included in Notes receivable and Other current assets and Notes receivable on the Company’s Consolidated Statements of Financial Position.
Notes receivable are typically considered delinquent when payment is not received for periods ranging from 60 to 120 days. The Company ceases accruing interest (nonaccrual status), considers a note receivable impaired, and establishes an allowance for credit loss when it is probable that all principal and interest amounts due will not be collected in accordance with the contractual terms of the note receivable. Cash payments received on nonaccrual status notes receivable, that do not bring the account contractually current, are first applied to contractually owed past due interest, with any remainder applied to principle.principal. Accrual of interest is generally resumed when the note receivable becomes contractually current.
In determining the allowance for credit losses for notes receivable, we consider the historical payment experience and other factors that are expected to have a specific impact on the counterparty’s ability to pay. In addition, the Company monitors the credit ratings of the counterparties from which we have notes receivable.
Inventories
The Company generally values inventory at average cost.
Gas inventory of $43$52 million and $44$43 million as of December 31, 2010 2011and 2009,2010, respectively, at MichCon is determined using thelast-in, first-out (LIFO) method. At December 31, 2010,2011, the replacement cost of gas remaining in storage exceeded the LIFO cost by $147 million.$95 million. At December 31, 2009,2010, the replacement cost of gas remaining in storage exceeded the LIFO cost by $218 million.$147 million.
Property, Retirement and Maintenance, and Depreciation, Depletion and Amortization
Property is stated at cost and includes construction-related labor, materials, overheads and, for utility property, an allowance for funds used during construction (AFUDC). The cost of utility properties retired, including the cost of removal, less salvage value, is charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2.
Non-utility property is depreciated over its estimated useful life using straight-line declining-balance orand units-of-production methods.
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The Company credits depreciation, depletion and amortization expense when it establishes regulatory assets for plant-related costs such as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when it amortizes these regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.
Approximately $3$23 million and $13$3 million of expenses related to Fermi 2 refueling outages were accrued at December 31, 2011 and December 31, 2010 and December 31, 2009,, respectively. Amounts are accrued on a pro-rata basis over an18-month18-month period that coincides with scheduled refueling outages at Fermi 2. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC.
See Note 7.
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11.
The cost of nuclear fuel is capitalized. The amortization of nuclear fuel is included within Fuel, purchased power, and gas in the Consolidated Statement of Operations and is recorded using the units-of-production method.
Unconventional Gas Production
The Company follows the successful efforts method of accounting for investments in oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well contains proved reserves. If an exploratory well does not contain proved reserves, the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining properties without economical quantities of proved reserves are expensed as incurred. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on aproperty-by-property basis, are considered not to be realizable. Depreciation, depletion and amortization of proved gas properties are determined using theunits-of-production method.
Long-Lived Assets
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.
Intangible Assets
The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Summary of intangible assets as of December 31:
| (In millions) | 2011 | 2010 | |||||
| Emission allowances | $ | 9 | $ | 9 | |||
| Renewable energy credits | 27 | 17 | |||||
| Contract intangible assets | 65 | 63 | |||||
| 101 | 89 | ||||||
| Less accumulated amortization | 28 | 22 | |||||
| Intangible assets, net | $ | 73 | $ | 67 | |||
Emission allowances and renewable energy credits are charged to expense, using average cost, as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $9 million at December 31, 2010 and 2009. The Company’s intangible assets related to renewable energy credits were $17 million at December 31, 2010. The Company had no renewable energy credits at December 31, 2009. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2010 were $63 million and $22 million, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2009 were $64 million and $19 million, respectively. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 43 to 3020 years. Intangible assets amortization expense was $4$5 million in 2010, $42011, $4 million in 20092010 and $7$4 million in 2008.2009. Amortization expense of intangible assets is estimated to be $4$3 million annually for 20112012 through 2015.2016.
Excise and Sales Taxes
The Company records the billing of excise and sales taxes as a receivable with an offsetting payable to the applicable taxing authority, with no net impact on the Consolidated Statements of Operations.
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Deferred Debt Costs
The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to the Company’s electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.
Investments in Debt and Equity Securities
The Company generally classifies investments in debt and equity securities as either trading oravailable-for-sale and has recorded such investments at market value with unrealized gains or losses included in earnings
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or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s equity investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the equity investment being written down to its estimated fair value. See Note 4.3.
Offsetting Amounts Related to Certain Contracts
The Company offsets the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting agreement, which reduces both the Company’s total assets and total liabilities. As of December 31, 2011 and December 31, 2010 and December 31, 2009,, the total cash collateral posted, net of cash collateral received, was $77$71 million and $117$77 million, respectively. Derivative assets and derivative liabilities are shown net of collateral of $9$19 million and $33$74 million, respectively, as of December 31, 20102011 and $34$9 million and $120$53 million, respectively, as of December 31, 2009.2010. The Company recorded cash collateral received of $2 million and cash collateral paid of $35$16 million not related to unrealized derivative positions as of December 31, 2010.2011. The Company recorded cash collateral received of $1$2 million and cash collateral paid of $32$35 million not related to unrealized derivative positions, as of December 31, 2009.2010. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.
Government Grants
Grants are recognized when there is reasonable assurance that the grant will be received and that any conditions associated with the grant will be met. When grants are received related to Property, Plant and Equipment, the Company reduces the basis of the assets on the Consolidated Statements of Financial Position, resulting in lower depreciation expense over the life of the associated asset. Grants received related to expenses are reflected as a reduction of the associated expense in the period in which the expense is incurred.
Other Accounting Policies
See the following notes for other accounting policies impacting the Company’s consolidated financial statements:
| Note | Title | |
| 3 | ||
| Fair Value | ||
| Financial and Other Derivative Instruments | ||
| Goodwill | ||
| Asset Retirement | ||
| Regulatory Matters | ||
| Income Taxes | ||
| Retirement Benefits and Trusteed Assets | ||
| Stock-based Compensation | ||
64 Table of Contents |
76
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
NOTE 3 — FAIR VALUE
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which was immaterial at December 31, 2011 and December 31, 2010 and December 31, 2009.. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
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A fair value hierarchy has been established, whichthat prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined as follows:
Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.
Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.
65
The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:2011:
| Netting | Net Balance at | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | December 31, 2010 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
| Nuclear decommissioning trusts | $ | 599 | $ | 340 | $ | — | $ | — | $ | 939 | ||||||||||
| Other investments(1) | 56 | 55 | — | — | 111 | |||||||||||||||
| Derivative assets: | ||||||||||||||||||||
| Foreign currency exchange contracts | — | 20 | — | (20 | ) | — | ||||||||||||||
| Commodity Contracts: | ||||||||||||||||||||
| Natural Gas | 1,846 | 128 | 12 | (1,960 | ) | 26 | ||||||||||||||
| Electricity | — | 649 | 117 | (589 | ) | 177 | ||||||||||||||
| Other | 68 | 4 | 4 | (71 | ) | 5 | ||||||||||||||
| Total derivative assets | 1,914 | 801 | 133 | (2,640 | ) | 208 | ||||||||||||||
| Total | $ | 2,569 | $ | 1,196 | $ | 133 | $ | (2,640 | ) | $ | 1,258 | |||||||||
| Level 1 | Level 2 | Level 3 | Netting Adjustments (2) | Net Balance at December 31, 2011 | |||||||||||||||
| (In millions) | |||||||||||||||||||
| Assets: | |||||||||||||||||||
| Nuclear decommissioning trusts | $ | 577 | $ | 360 | $ | — | $ | — | $ | 937 | |||||||||
| Other investments (1) | 57 | 54 | — | — | 111 | ||||||||||||||
| Derivative assets: | |||||||||||||||||||
| Foreign currency exchange contracts | — | 3 | — | (3 | ) | — | |||||||||||||
| Commodity Contracts: | |||||||||||||||||||
| Natural Gas | 1,926 | 78 | 20 | (1,991 | ) | 33 | |||||||||||||
| Electricity | — | 523 | 224 | (490 | ) | 257 | |||||||||||||
| Other | 23 | 2 | 6 | (25 | ) | 6 | |||||||||||||
| Total derivative assets | 1,949 | 606 | 250 | (2,509 | ) | 296 | |||||||||||||
| Total | $ | 2,583 | $ | 1,020 | $ | 250 | $ | (2,509 | ) | $ | 1,344 | ||||||||
| Liabilities: | |||||||||||||||||||
| Derivative liabilities: | |||||||||||||||||||
| Foreign currency exchange contracts | $ | — | $ | (5 | ) | $ | — | $ | 3 | $ | (2 | ) | |||||||
| Interest rate contracts | — | (1 | ) | — | — | (1 | ) | ||||||||||||
| Commodity Contracts: | |||||||||||||||||||
| Natural Gas | (1,940 | ) | (126 | ) | (14 | ) | 1,976 | (104 | ) | ||||||||||
| Electricity | — | (513 | ) | (192 | ) | 565 | (140 | ) | |||||||||||
| Other | (19 | ) | (1 | ) | — | 20 | — | ||||||||||||
| Total derivative liabilities | (1,959 | ) | (646 | ) | (206 | ) | 2,564 | (247 | ) | ||||||||||
| Total | $ | (1,959 | ) | $ | (646 | ) | $ | (206 | ) | $ | 2,564 | $ | (247 | ) | |||||
| Net Assets as of December 31, 2011 | $ | 624 | $ | 374 | $ | 44 | $ | 55 | $ | 1,097 | |||||||||
| Assets: | |||||||||||||||||||
| Current | $ | 1,571 | $ | 520 | $ | 181 | $ | (2,050 | ) | $ | 222 | ||||||||
| Noncurrent (3) | 1,012 | 500 | 69 | (459 | ) | 1,122 | |||||||||||||
| Total Assets | $ | 2,583 | $ | 1,020 | $ | 250 | $ | (2,509 | ) | $ | 1,344 | ||||||||
| Liabilities: | |||||||||||||||||||
| Current | $ | (1,603 | ) | $ | (527 | ) | $ | (152 | ) | $ | 2,124 | $ | (158 | ) | |||||
| Noncurrent | (356 | ) | (119 | ) | (54 | ) | 440 | (89 | ) | ||||||||||
| Total Liabilities | $ | (1,959 | ) | $ | (646 | ) | $ | (206 | ) | $ | 2,564 | $ | (247 | ) | |||||
| Net Assets as of December 31, 2011 | $ | 624 | $ | 374 | $ | 44 | $ | 55 | $ | 1,097 | |||||||||
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| Netting | Net Balance at | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | December 31, 2010 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
Liabilities: | ||||||||||||||||||||
| Derivative liabilities: | ||||||||||||||||||||
| Foreign currency exchange contracts | $ | — | $ | (30 | ) | $ | — | $ | 20 | $ | (10 | ) | ||||||||
| Interest rate contracts | — | (1 | ) | — | — | (1 | ) | |||||||||||||
| Commodity Contracts: | ||||||||||||||||||||
| Natural Gas | (1,844 | ) | (263 | ) | (11 | ) | 1,955 | (163 | ) | |||||||||||
| Electricity | — | (653 | ) | (63 | ) | 643 | (73 | ) | ||||||||||||
| Other | (63 | ) | (8 | ) | — | 66 | (5 | ) | ||||||||||||
| Total derivative liabilities | (1,907 | ) | (955 | ) | (74 | ) | 2,684 | (252 | ) | |||||||||||
| Total | $ | (1,907 | ) | $ | (955 | ) | $ | (74 | ) | $ | 2,684 | $ | (252 | ) | ||||||
| Net Assets as of December 31, 2010 | $ | 662 | $ | 241 | $ | 59 | $ | 44 | $ | 1,006 | ||||||||||
Assets: | ||||||||||||||||||||
| Current | $ | 1,299 | $ | 663 | $ | 49 | $ | (1,880 | ) | $ | 131 | |||||||||
| Noncurrent(3) | 1,270 | 533 | 84 | (760 | ) | 1,127 | ||||||||||||||
| Total Assets | $ | 2,569 | $ | 1,196 | $ | 133 | $ | (2,640 | ) | $ | 1,258 | |||||||||
Liabilities: | ||||||||||||||||||||
| Current | $ | (1,290 | ) | $ | (730 | ) | $ | (21 | ) | $ | 1,899 | $ | (142 | ) | ||||||
| Noncurrent | (617 | ) | (225 | ) | (53 | ) | 785 | (110 | ) | |||||||||||
| Total Liabilities | $ | (1,907 | ) | $ | (955 | ) | $ | (74 | ) | $ | 2,684 | $ | (252 | ) | ||||||
| Net Assets as of December 31, 2010 | $ | 662 | $ | 241 | $ | 59 | $ | 44 | $ | 1,006 | ||||||||||
The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2009:2010:
| Netting | Net Balance at | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | December 31, 2009 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
| Cash equivalents | $ | 15 | $ | — | $ | — | $ | — | $ | 15 | ||||||||||
| Nuclear decommissioning trusts | 549 | 268 | — | — | 817 | |||||||||||||||
| Other Investments(1) | 50 | 57 | — | — | 107 | |||||||||||||||
| Derivative assets | 1,080 | 1,207 | 385 | (2,347 | ) | 325 | ||||||||||||||
| Total | $ | 1,694 | $ | 1,532 | $ | 385 | $ | (2,347 | ) | $ | 1,264 | |||||||||
Liabilities: | ||||||||||||||||||||
| Derivative liabilities | $ | (1,120 | ) | $ | (1,370 | ) | $ | (361 | ) | $ | 2,433 | $ | (418 | ) | ||||||
| Total | $ | (1,120 | ) | $ | (1,370 | ) | $ | (361 | ) | $ | 2,433 | $ | (418 | ) | ||||||
| Net Assets at December 31, 2009 | $ | 574 | $ | 162 | $ | 24 | $ | 86 | $ | 846 | ||||||||||
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| Level 1 | Level 2 | Level 3 | Netting Adjustments (2) | Net Balance at December 31, 2010 | |||||||||||||||
| (In millions) | |||||||||||||||||||
| Assets: | |||||||||||||||||||
| Nuclear decommissioning trusts | $ | 599 | $ | 340 | $ | — | $ | — | $ | 939 | |||||||||
| Other investments (1) | 56 | 55 | — | — | 111 | ||||||||||||||
| Derivative assets: | |||||||||||||||||||
| Foreign currency exchange contracts | — | 20 | — | (20 | ) | — | |||||||||||||
| Commodity Contracts: | |||||||||||||||||||
| Natural Gas | 1,846 | 128 | 12 | (1,960 | ) | 26 | |||||||||||||
| Electricity | — | 649 | 117 | (589 | ) | 177 | |||||||||||||
| Other | 68 | 4 | 4 | (71 | ) | 5 | |||||||||||||
| Total derivative assets | 1,914 | 801 | 133 | (2,640 | ) | 208 | |||||||||||||
| Total | $ | 2,569 | $ | 1,196 | $ | 133 | $ | (2,640 | ) | $ | 1,258 | ||||||||
| Liabilities: | |||||||||||||||||||
| Derivative liabilities: | |||||||||||||||||||
| Foreign currency exchange contracts | $ | — | $ | (30 | ) | $ | — | $ | 20 | $ | (10 | ) | |||||||
| Interest rate contracts | — | (1 | ) | — | — | (1 | ) | ||||||||||||
| Commodity Contracts: | |||||||||||||||||||
| Natural Gas | (1,844 | ) | (263 | ) | (11 | ) | 1,955 | (163 | ) | ||||||||||
| Electricity | — | (653 | ) | (63 | ) | 643 | (73 | ) | |||||||||||
| Other | (63 | ) | (8 | ) | — | 66 | (5 | ) | |||||||||||
| Total derivative liabilities | (1,907 | ) | (955 | ) | (74 | ) | 2,684 | (252 | ) | ||||||||||
| Total | $ | (1,907 | ) | $ | (955 | ) | $ | (74 | ) | $ | 2,684 | $ | (252 | ) | |||||
| Net Assets as of December 31, 2010 | $ | 662 | $ | 241 | $ | 59 | $ | 44 | $ | 1,006 | |||||||||
| Assets: | |||||||||||||||||||
| Current | $ | 1,299 | $ | 663 | $ | 49 | $ | (1,880 | ) | $ | 131 | ||||||||
| Noncurrent (3) | 1,270 | 533 | 84 | (760 | ) | 1,127 | |||||||||||||
| Total Assets | $ | 2,569 | $ | 1,196 | $ | 133 | $ | (2,640 | ) | $ | 1,258 | ||||||||
| Liabilities: | |||||||||||||||||||
| Current | $ | (1,290 | ) | $ | (730 | ) | $ | (21 | ) | $ | 1,899 | $ | (142 | ) | |||||
| Noncurrent | (617 | ) | (225 | ) | (53 | ) | 785 | (110 | ) | ||||||||||
| Total Liabilities | $ | (1,907 | ) | $ | (955 | ) | $ | (74 | ) | $ | 2,684 | $ | (252 | ) | |||||
| Net Assets as of December 31, 2010 | $ | 662 | $ | 241 | $ | 59 | $ | 44 | $ | 1,006 | |||||||||
| (1) | Excludes cash surrender value of life insurance investments. |
| (2) | Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties. |
| (3) | Includes |
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The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 20102011 and 2009:2010:
| Year Ended December 31, 2010 | ||||||||||||||||
| Natural Gas | Electricity | Other | Total | |||||||||||||
| (In millions) | ||||||||||||||||
| Asset balance as of January 1, 2010 | $ | 2 | $ | 19 | $ | 3 | $ | 24 | ||||||||
| Changes in fair value recorded in income | 4 | 64 | 1 | 69 | ||||||||||||
| Changes in fair value recorded in regulatory assets/liabilities | — | — | 6 | 6 | ||||||||||||
| Purchases, issuances and settlements | (8 | ) | (73 | ) | (6 | ) | (87 | ) | ||||||||
| Transfers in/out of Level 3 | 3 | 44 | — | 47 | ||||||||||||
| Asset balance as of December 31, 2010 | $ | 1 | $ | 54 | $ | 4 | $ | 59 | ||||||||
| The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2010 | $ | (4 | ) | $ | (6 | ) | $ | 1 | $ | (9 | ) | |||||
| Year Ended December 31, 2011 | |||||||||||||||
| Natural Gas | Electricity | Other | Total | ||||||||||||
| (In millions) | |||||||||||||||
| Net Assets as of January 1, 2011 | $ | 1 | $ | 54 | $ | 4 | $ | 59 | |||||||
| Transfers into Level 3 | — | 4 | — | 4 | |||||||||||
| Transfers out of Level 3 | 1 | (25 | ) | — | (24 | ) | |||||||||
| Total gains: | |||||||||||||||
| Included in earnings | 7 | 77 | 3 | 87 | |||||||||||
| Recorded in regulatory assets/liabilities | — | — | 2 | 2 | |||||||||||
| Purchases, issuances and settlements: | |||||||||||||||
| Purchases | — | 3 | — | 3 | |||||||||||
| Settlements | (3 | ) | (81 | ) | (3 | ) | (87 | ) | |||||||
| Net Assets as of December 31, 2011 | $ | 6 | $ | 32 | $ | 6 | $ | 44 | |||||||
| The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2011 | $ | 8 | $ | 65 | $ | 2 | $ | 75 | |||||||
| Year Ended December 31, 2009 | ||||||||||||||||
| Natural Gas | Electricity | Other | Total | |||||||||||||
| (In millions) | ||||||||||||||||
| Asset (Liability) balance as of January 1, 2009 | $ | (183 | ) | $ | (5 | ) | $ | 5 | $ | (183 | ) | |||||
| Changes in fair value recorded in income | (17 | ) | 59 | (1 | ) | 41 | ||||||||||
| Changes in fair value recorded in other comprehensive income | 8 | — | — | 8 | ||||||||||||
| Purchases, issuances and settlements | (15 | ) | (30 | ) | 1 | (44 | ) | |||||||||
| Transfers in/out of Level 3 | 209 | (5 | ) | (2 | ) | 202 | ||||||||||
| Asset (Liability) balance as of December 31, 2009 | $ | 2 | $ | 19 | $ | 3 | $ | 24 | ||||||||
| The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2009 | $ | (60 | ) | $ | 154 | $ | (1 | ) | $ | 93 | ||||||
| Year Ended December 31, 2010 | |||||||||||||||
| Natural Gas | Electricity | Other | Total | ||||||||||||
| (In millions) | |||||||||||||||
| Net Assets as of January 1, 2010 | $ | 2 | $ | 19 | $ | 3 | $ | 24 | |||||||
| Changes in fair value included in earnings | 4 | 64 | 1 | 69 | |||||||||||
| Changes in fair value recorded in regulatory assets/liabilities | — | — | 6 | 6 | |||||||||||
| Purchases, issuances and settlements | (8 | ) | (73 | ) | (6 | ) | (87 | ) | |||||||
| Transfers in/out of Level 3 | 3 | 44 | — | 47 | |||||||||||
| Net Assets as of December 31, 2010 | $ | 1 | $ | 54 | $ | 4 | $ | 59 | |||||||
| The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2010 | $ | (4 | ) | $ | (6 | ) | $ | 1 | $ | (9 | ) | ||||
Transfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in/in and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. No significant transfers between Level 1 and 2 occurred in yearsFor the year ended December 31, 2010 and December 31, 2009. Transfers2011, $25 million of net assets reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 23 to Level 3 representing $92, and $4 million of net assets reflectreflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes forwere transferred from Level 2 to Level 3. For the year ended December 31, 2010. Transfers from Level 3 to Level 2
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DTE Energy Company
Nuclear Decommissioning Trusts and Other Investments
The nuclear decommissioning trusts and other investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.
Derivative Assets and Liabilities
Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded andover-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. DTE Energy considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. DTE Energy monitors the prices that are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. DTE Energy has obtained an understanding of how these prices are derived. Additionally, DTE Energy selectively corroborates the fair value of its transactions by comparison of market-based price sources. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period.
Fair Value of Financial Instruments
The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial
81
instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 54 for further fair value information on financial and derivative instruments.
| December 31, 2011 | December 31, 2010 | ||||||||||||||
| Fair Value | Carrying Value | Fair Value | Carrying Value | ||||||||||||
| Long-Term Debt | $ | 8.8 | billion | $ | 7.7 | billion | $ | 8.5 | billion | $ | 8.0 | billion | |||
Nuclear Decommissioning Trust Funds
Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. See Note 9 for additional information.
See Note 8.
The following table summarizes the fair value of the nuclear decommissioning trust fund assets:
| December 31 | December 31 | |||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| Fermi 2 | $ | 910 | $ | 790 | ||||
| Fermi 1 | 3 | 3 | ||||||
| Low level radioactive waste | 26 | 24 | ||||||
| Total | $ | 939 | $ | 817 | ||||
December 31 2011 | December 31 2010 | ||||||
| (In millions) | |||||||
| Fermi 2 | $ | 915 | $ | 910 | |||
| Fermi 1 | 3 | 3 | |||||
| Low level radioactive waste | 19 | 26 | |||||
| Total | $ | 937 | $ | 939 | |||
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At December 31, 2010,2011, investments in the nuclear decommissioning trust funds consisted of approximately 61%57% in publicly traded equity securities, 38%41% in fixed debt instruments and 1%2% in cash equivalents. At December 31, 2009,2010, investments in the nuclear decommissioning trust funds consisted of approximately 51%61% in publicly traded equity securities, 48%38% in fixed debt instruments and 1% in cash equivalents. The debt securities at both December 31, 2011 and December 31, 2010 and December 31, 2009 had an average maturity of approximately 67 and 56 years, respectively.
The costs of securities sold are determined on the basis of specific identification. The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:
| Year Ended December 31 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Realized gains | $ | 192 | $ | 37 | $ | 34 | ||||||
| Realized losses | $ | (83 | ) | $ | (55 | ) | $ | (49 | ) | |||
| Proceeds from sales of securities | $ | 377 | $ | 295 | $ | 232 | ||||||
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| Year Ended December 31 | |||||||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Realized gains | $ | 46 | $ | 192 | $ | 37 | |||||
| Realized losses | $ | (38 | ) | $ | (83 | ) | $ | (55 | ) | ||
| Proceeds from sales of securities | $ | 80 | $ | 377 | $ | 295 | |||||
Realized gains and losses from the sale of securities for the Fermi 2 trust and the low level radioactive waste funds are recorded to the Regulatory asset and Nuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:
| Fair | Unrealized | |||||||
| Value | Gains | |||||||
| (In millions) | ||||||||
| As of December 31, 2010 | ||||||||
| Equity securities | $ | 572 | $ | 77 | ||||
| Debt securities | 361 | 11 | ||||||
| Cash and cash equivalents | 6 | — | ||||||
| $ | 939 | $ | 88 | |||||
| As of December 31, 2009 | ||||||||
| Equity securities | $ | 420 | $ | 135 | ||||
| Debt securities | 388 | 17 | ||||||
| Cash and cash equivalents | 9 | — | ||||||
| $ | 817 | $ | 152 | |||||
Fair Value | Unrealized Gains | ||||||
| (In millions) | |||||||
| As of December 31, 2011 | |||||||
| Equity securities | $ | 533 | $ | 80 | |||
| Debt securities | 385 | 22 | |||||
| Cash and cash equivalents | 19 | — | |||||
| $ | 937 | $ | 102 | ||||
| As of December 31, 2010 | |||||||
| Equity securities | $ | 572 | $ | 77 | |||
| Debt securities | 361 | 11 | |||||
| Cash and cash equivalents | 6 | — | |||||
| $ | 939 | $ | 88 | ||||
Securities held in the nuclear decommissioning trust funds are classified asavailable-for-sale. As Detroit Edison does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be other than temporary impairments.
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Other Available- For- Sale Securities
The following table summarizes the fair value of the Company’s investment inavailable-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Fair Value | Carrying value | Fair Value | Carrying Value | |||||||||||||
| (In millions) | ||||||||||||||||
| Cash equivalents | $ | 133 | $ | 133 | $ | 106 | $ | 106 | ||||||||
| Equity securities | $ | 6 | $ | 6 | $ | 11 | $ | 11 | ||||||||
| December 31, 2011 | December 31, 2010 | ||||||||||||||
| (In millions) | Fair Value | Carrying value | Fair Value | Carrying Value | |||||||||||
| Cash equivalents | $ | 140 | $ | 140 | $ | 133 | $ | 133 | |||||||
| Equity securities | $ | 5 | $ | 5 | $ | 6 | $ | 6 | |||||||
At December 31, 20102011 and 2009,2010, these securities are comprised primarily of money-market and equity securities. During the year ended December 31, 2011 and December 31, 2010no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the period. During the year ended December 31, 2009, $3 million of unrealized losses onavailable-for-sale securities were reclassified out of other comprehensive income into earnings. This reclassification includes an other than temporary impairment of equity securities of $4 million.periods. Gains (losses) related to trading securities held at December 31, 2011, 2010 2009,, and 20082009 were $7$3 million $8, $7 million and $(14)$8 million, respectively.
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| FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS |
The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for the derivative are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.
The Company’s primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency exchange. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment and the coal marketing activities of its Power and Industrial Projects segment. Contracts classified as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, unconventional gas and oil reserves, power transmission, pipeline transportation and certain storage assets.
Electric Utility — Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.
Gas Utility — MichCon purchases, stores, transports, gathers, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through March 2014. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.
Gas Storage and Pipelines —This segment is primarily engaged in services related to the transportation and storage of natural gas. Fixed-pricedPrimarily fixed-priced contracts are used in the marketing and management of transportation and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.
Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional natural gas and oil project development and production. The Company usesmay use derivative contracts to manage changes in the price of natural gas and crude oil. In 2010 and prior periods, these derivatives were designated as cash flow hedges. Approximately $1 million after-tax gain recorded in Accumulated other comprehensive income at the end of 2009 was reclassified to earnings as the related production affected earnings through 2010. Total pre-tax gains from derivative contracts on natural gas during 2010 were approximately $3 million.
Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not
84
derivatives and are therefore accounted for under the accrual method. The segment also engages in coal marketing which includes the marketing and trading of physical
71
coal and coal financial instruments, and forward contracts for the purchase and sale of emissionsemission allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings.
Energy Trading — Commodity Price Risk —Energy Trading markets and trades electricity and natural gas physical products and energy financial instruments, and provides riskenergy and asset management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations in its operations. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.
Energy Trading — Foreign Currency Exchange Risk —Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.
Corporate and Other — Interest Rate Risk —The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company subsequently issued long-term debt and terminated these hedges at a cost that is included in other comprehensive loss. Amounts recorded in other comprehensive loss will be reclassified to interest expense through 2033. In 2011,2012, the Company estimates reclassifying less than $1$1 million of losses to earnings.
Credit Risk —The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty. The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its December 31, 20102011 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.
Derivative Activities
The Company manages its MTMmark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year). The following describe the four categories of activities represented by their operating characteristics and key risks:
Asset Optimization — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with power transmission, gas transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.
85
Marketing and Origination — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.
Fundamentals Based Trading — Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.
Other — Includes derivative activity at Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR
72
mechanism when realized.
The following representstables present the fair value of derivative instruments as of December 31, 2010:2011:
| Derivative Assets | Derivative Liabilities | |||||||
| (In millions) | ||||||||
Derivatives designated as hedging instruments: | ||||||||
| Interest rate contracts | $ | — | $ | (1 | ) | |||
Total derivatives designated as hedging instruments: | $ | — | $ | (1 | ) | |||
Derivatives not designated as hedging instruments: | ||||||||
| Foreign currency exchange contracts | $ | 20 | $ | (30 | ) | |||
| Commodity Contracts: | ||||||||
| Natural Gas | 1,986 | (2,118 | ) | |||||
| Electricity | 766 | (716 | ) | |||||
| Other | 76 | (71 | ) | |||||
Total derivatives not designated as hedging instruments: | $ | 2,848 | $ | (2,935 | ) | |||
Total derivatives: | ||||||||
| Current | $ | 2,011 | $ | (2,041 | ) | |||
| Noncurrent | 837 | (895 | ) | |||||
Total derivatives | $ | 2,848 | $ | (2,936 | ) | |||
| Derivative Assets | Derivative Liabilities | ||||||
| (In millions) | |||||||
| Derivatives designated as hedging instruments: | |||||||
| Interest rate contracts | $ | — | $ | (1 | ) | ||
| Derivatives not designated as hedging instruments: | |||||||
| Foreign currency exchange contracts | $ | 3 | $ | (5 | ) | ||
| Commodity Contracts: | |||||||
| Natural Gas | 2,024 | (2,080 | ) | ||||
| Electricity | 747 | (705 | ) | ||||
| Other | 31 | (20 | ) | ||||
| Total derivatives not designated as hedging instruments: | $ | 2,805 | $ | (2,810 | ) | ||
| Total derivatives: | |||||||
| Current | $ | 2,272 | $ | (2,282 | ) | ||
| Noncurrent | 533 | (529 | ) | ||||
| Total derivatives | $ | 2,805 | $ | (2,811 | ) | ||
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| Current | Noncurrent | Current | Noncurrent | |||||||||||||
Reconciliation of derivative instruments to Consolidated Statements of Financial Position: | ||||||||||||||||
| Total fair value of derivatives | $ | 2,011 | $ | 837 | $ | (2,041 | ) | $ | (895 | ) | ||||||
| Counterparty netting | (1,871 | ) | (760 | ) | 1,871 | 760 | ||||||||||
| Collateral adjustment | (9 | ) | — | 28 | 25 | |||||||||||
Total derivatives as reported | $ | 131 | $ | 77 | $ | (142 | ) | $ | (110 | ) | ||||||
86
| Derivative Assets | Derivative Liabilities | ||||||||||||||
| Current | Noncurrent | Current | Noncurrent | ||||||||||||
| Reconciliation of derivative instruments to Consolidated Statements of Financial Position: | |||||||||||||||
| Total fair value of derivatives | $ | 2,272 | $ | 533 | $ | (2,282 | ) | $ | (529 | ) | |||||
| Counterparty netting | (2,050 | ) | (440 | ) | 2,050 | 440 | |||||||||
| Collateral adjustment | — | (19 | ) | 74 | — | ||||||||||
| Total derivatives as reported | $ | 222 | $ | 74 | $ | (158 | ) | $ | (89 | ) | |||||
The following representstables present the fair value of derivative instruments as of December 31, 2009:
| Derivative Assets | Derivative Liabilities | |||||||
| (In millions) | ||||||||
Derivatives designated as hedging instruments: | ||||||||
| Commodity Contracts — Natural Gas | $ | 2 | $ | — | ||||
Derivatives not designated as hedging instruments: | ||||||||
| Foreign currency exchange contracts | $ | 24 | $ | (31 | ) | |||
| Commodity Contracts: | ||||||||
| Natural Gas | 1,323 | (1,552 | ) | |||||
| Electricity | 1,304 | (1,241 | ) | |||||
| Other | 19 | (27 | ) | |||||
Total derivatives not designated as hedging instruments: | $ | 2,670 | $ | (2,851 | ) | |||
Total derivatives: | ||||||||
| Current | $ | 1,860 | $ | (1,951 | ) | |||
| Noncurrent | 812 | (900 | ) | |||||
Total derivatives | $ | 2,672 | $ | (2,851 | ) | |||
| Derivative Assets | Derivative Liabilities | |||||||||||||||
| Current | Noncurrent | Current | Noncurrent | |||||||||||||
Reconciliation of derivative instruments to Consolidated Statements of Financial Position: | ||||||||||||||||
| Total fair value of derivatives | $ | 1,860 | $ | 812 | $ | (1,951 | ) | $ | (900 | ) | ||||||
| Counterparty netting | (1,644 | ) | (669 | ) | 1,644 | 669 | ||||||||||
| Collateral adjustment | (7 | ) | (27 | ) | 87 | 33 | ||||||||||
Total derivatives as reported | $ | 209 | $ | 116 | $ | (220 | ) | $ | (198 | ) | ||||||
| Derivative Assets | Derivative Liabilities | ||||||
| (In millions) | |||||||
| Derivatives designated as hedging instruments: | |||||||
| Interest rate contracts | $ | — | $ | (1 | ) | ||
| Derivatives not designated as hedging instruments: | |||||||
| Foreign currency exchange contracts | $ | 20 | $ | (30 | ) | ||
| Commodity Contracts: | |||||||
| Natural Gas | 1,986 | (2,118 | ) | ||||
| Electricity | 766 | (716 | ) | ||||
| Other | 76 | (71 | ) | ||||
| Total derivatives not designated as hedging instruments: | $ | 2,848 | $ | (2,935 | ) | ||
| Total derivatives: | |||||||
| Current | $ | 2,011 | $ | (2,041 | ) | ||
| Noncurrent | 837 | (895 | ) | ||||
| Total derivatives | $ | 2,848 | $ | (2,936 | ) | ||
73
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| Derivative Assets | Derivative Liabilities | ||||||||||||||
| Current | Noncurrent | Current | Noncurrent | ||||||||||||
| Reconciliation of derivative instruments to Consolidated Statements of Financial Position: | |||||||||||||||
| Total fair value of derivatives | $ | 2,011 | $ | 837 | $ | (2,041 | ) | $ | (895 | ) | |||||
| Counterparty netting | (1,871 | ) | (760 | ) | 1,871 | 760 | |||||||||
| Collateral adjustment | (9 | ) | — | 28 | 25 | ||||||||||
| Total derivatives as reported | $ | 131 | $ | 77 | $ | (142 | ) | $ | (110 | ) | |||||
The effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for years ended December 31, 2011 and December 31, 2010 and December 31, 2009 is as follows:
| Gain (Loss) | ||||||||||
| Recognized in | ||||||||||
| Income on | ||||||||||
| Location of Gain | Derivatives for | |||||||||
| (Loss) Recognized | Years Ended | |||||||||
| in Income | December 31 | |||||||||
| Derivatives not Designated as Hedging Instruments | On Derivatives | 2010 | 2009 | |||||||
| (In millions) | ||||||||||
| Foreign currency exchange contracts | Operating Revenue | $ | (14 | ) | $ | (24 | ) | |||
| Commodity Contracts: | ||||||||||
| Natural Gas | Operating Revenue | 61 | 179 | |||||||
| Natural Gas | Fuel, purchased power and gas | (8 | ) | 4 | ||||||
| Electricity | Operating Revenue | 80 | 19 | |||||||
| Other | Operating Revenue | 9 | (4 | ) | ||||||
| Other | Operation and maintenance | (5 | ) | 6 | ||||||
Total | $ | 123 | $ | 180 | ||||||
Location of Gain (Loss) Recognized in Income on Derivatives | Gain (Loss) Recognized in Income on Derivatives for Years Ended December 31 | ||||||||
| Derivatives not Designated as Hedging Instruments | 2011 | 2010 | |||||||
| (In millions) | |||||||||
| Foreign currency exchange contracts | Operating Revenue | $ | (2 | ) | $ | (14 | ) | ||
| Commodity Contracts: | |||||||||
| Natural Gas | Operating Revenue | 58 | 61 | ||||||
| Natural Gas | Fuel, purchased power and gas | (21 | ) | (8 | ) | ||||
| Electricity | Operating Revenue | 115 | 80 | ||||||
| Other | Operating Revenue | 9 | 9 | ||||||
| Other | Operation and maintenance | — | (5 | ) | |||||
| Total | $ | 159 | $ | 123 | |||||
The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position are $1were $3 million in losses related to Emissions recognized in Regulatory assets and $6 million in gains related to FTRs recognized in Regulatory liabilities for the year ended December 31, 2010,2011, and $14$1 million and $2 million in losses related to Emissions recognized in Regulatory assets and $6 million in gains related to FTRs recognized in Regulatory liabilities, respectively, for the year ended December 31, 2009.2010.
The following represents the cumulative gross volume of derivative contracts outstanding as of December 31, 2010:2011:
| Commodity | Number of Units | |||
| Natural Gas (MMBtu) | 770,624,682 | |||
| Electricity (MWh) | 48,286,149 | |||
| Foreign Currency Exchange ($ CAD) | 34,904,696 | |||
Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterpartiesand/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of December 31, 2010,2011, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date under both hard trigger and soft trigger provisions was approximately $234 million.$315 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.
88
| GOODWILL |
The Company has goodwill resulting from purchase business combinations.
The change in the carrying amount of goodwill for the fiscal years ended December 31, 2011and December 31, 2010 and December 31, 2009 is as follows:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| Balance as of January 1 | $ | 2,024 | $ | 2,037 | ||||
| Goodwill attributable to sale of subsidiary in Power and Industrial Projects | (4 | ) | — | |||||
| Goodwill attributable to sale of subsidiary in Gas Utility | — | (13 | ) | |||||
| Balance at December 31 | $ | 2,020 | $ | 2,024 | ||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Balance as of January 1 | $ | 2,020 | $ | 2,024 | |||
| Goodwill attributable to sale of subsidiary in Power and Industrial Projects segment | — | (4 | ) | ||||
| Balance at December 31 | $ | 2,020 | $ | 2,020 | |||
Summary of property by classification as of December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Property, Plant and Equipment | ||||||||
| Electric Utility | ||||||||
| Generation | $ | 9,268 | $ | 8,833 | ||||
| Distribution | 6,800 | 6,618 | ||||||
| Total Electric Utility | 16,068 | 15,451 | ||||||
| Gas Utility | ||||||||
| Distribution | 2,460 | 2,386 | ||||||
| Storage | 395 | 383 | ||||||
| Other | 991 | 1,013 | ||||||
| Total Gas Utility | 3,846 | 3,782 | ||||||
| Non-utility and other | 1,660 | 1,355 | ||||||
| Total | 21,574 | 20,588 | ||||||
Less Accumulated Depreciation, Depletion and Amortization | ||||||||
| Electric Utility | ||||||||
| Generation | (3,850 | ) | (3,890 | ) | ||||
| Distribution | (2,568 | ) | (2,243 | ) | ||||
| Total Electric Utility | (6,418 | ) | (6,133 | ) | ||||
| Gas Utility | ||||||||
| Distribution | (1,019 | ) | (972 | ) | ||||
| Storage | (108 | ) | (113 | ) | ||||
| Other | (512 | ) | (543 | ) | ||||
| Total Gas Utility | (1,639 | ) | (1,628 | ) | ||||
| Non-utility and other | (525 | ) | (396 | ) | ||||
| Total | (8,582 | ) | (8,157 | ) | ||||
Net Property, Plant and Equipment | $ | 12,992 | $ | 12,431 | ||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Property, Plant and Equipment | |||||||
| Electric Utility | |||||||
| Generation | $ | 9,785 | $ | 9,268 | |||
| Distribution | 7,003 | 6,800 | |||||
| Total Electric Utility | 16,788 | 16,068 | |||||
| Gas Utility | |||||||
| Distribution | 2,561 | 2,460 | |||||
| Storage | 406 | 395 | |||||
| Other | 902 | 991 | |||||
| Total Gas Utility | 3,869 | 3,846 | |||||
| Non-utility and other | 1,884 | 1,660 | |||||
| Total | 22,541 | 21,574 | |||||
| Less Accumulated Depreciation, Depletion and Amortization | |||||||
| Electric Utility | |||||||
| Generation | (3,946 | ) | (3,850 | ) | |||
| Distribution | (2,580 | ) | (2,568 | ) | |||
| Total Electric Utility | (6,526 | ) | (6,418 | ) | |||
| Gas Utility | |||||||
| Distribution | (1,041 | ) | (1,019 | ) | |||
| Storage | (127 | ) | (108 | ) | |||
| Other | (413 | ) | (512 | ) | |||
| Total Gas Utility | (1,581 | ) | (1,639 | ) | |||
| Non-utility and other | (688 | ) | (525 | ) | |||
| Total | (8,795 | ) | (8,582 | ) | |||
| Net Property, Plant and Equipment | $ | 13,746 | $ | 12,992 | |||
AFUDC capitalized during 2011 and 2010 was approximately $10 million.
75
The composite depreciation rate for Detroit Edison was approximately 3.3% in 2011, 2010 2009 and 2008.2009. The composite depreciation rate for MichCon was 2.5%2.3% in 2010, 3.1%2011, 2.5% in 20092010 and 3.2%3.1% in 2008. In March 2010, the MPSC issued an order reducing MichCon’s composite depreciation rates effective April 1, 2010.2009.
The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 20102011 follows:
| Estimated Useful Lives in Years | ||||||||||||
| Utility | Generation | Distribution | Transmission | |||||||||
| Electric | 40 | 37 | N/A | |||||||||
| Gas | N/A | 62 | 61 | |||||||||
| Estimated Useful Lives in Years | ||||||
| Utility | Generation | Distribution | Transmission | |||
| Electric | 46 | 43 | N/A | |||
| Gas | N/A | 62 | 61 | |||
The estimated useful lives for major classes of non-utility assets and facilities ranges from 3 to 55 years.
Capitalized software costs are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation, depletion and amortization on the Consolidated Statements of Financial Position. The Company capitalizes the costs associated with computer software it develops or obtains for use in its business. The Company amortizes capitalized software costs on a straight-line basis over the expected period of benefit, ranging from 3 to 20 years.
Capitalized software costs amortization expense was $65$65 million in 2011 and 2010 $66 and $66 million in 2009 and $54 million in 2008.. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 20102011 were $602$623 million and $252$300 million, respectively. The gross carrying amount and accumulated amortization of capitalized software costs at December 31, 20092010 were $613$602 million and $234$252 million, respectively. Amortization expense of capitalized software costs is estimated to be approximately $66$64 million annually for 20112012 through 2015.2016.
Gross property under capital leases was $153$57 million and $153 million at December 31, 2011 and December 31, 2010 and December 31, 2009., respectively. Accumulated amortization of property under capital leases was $114$34 million and $93$114 million at December 31, 2011 and December 31, 2010 and December 31, 2009,, respectively.
NOTE 7 — JOINTLY OWNED UTILITY PLANT |
Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Detroit Edison’s share of direct expenses of the jointly owned plants are included in Fuel, purchased power and gas and Operation and maintenance expenses in the Consolidated Statements of Operations. Ownership information of the two utility plants as of December 31, 20102011 was as follows:
| Ludington | ||||||||
| Hydroelectric | ||||||||
| Belle River | Pumped Storage | |||||||
| In-service date | 1984-1985 | 1973 | ||||||
| Total plant capacity | 1,270MW | 1,872MW | ||||||
| Ownership interest | * | 49 | % | |||||
| Investment (in millions) | $ | 1,635 | $ | 199 | ||||
| Accumulated depreciation (in millions) | $ | 923 | $ | 117 | ||||
| Belle River | Ludington Hydroelectric Pumped Storage | ||||||
| In-service date | 1984-1985 | 1973 | |||||
| Total plant capacity | 1,270 | MW | 1,872 | MW | |||
| Ownership interest | * | 49 | % | ||||
| Investment (in millions) | $ | 1,645 | $ | 199 | |||
| Accumulated depreciation (in millions) | $ | 943 | $ | 158 | |||
90
Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2.
Belle River
The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities. The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.
Ludington Hydroelectric Pumped Storage
Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.
76
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued) NOTE 8 — ASSET RETIREMENT OBLIGATIONS |
The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations forplants, gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal ofpipelines, asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations atplants, certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate. In its regulated operations, the Company recognizes regulatory assets or liabilities for timing differences in expense recognition for legal asset retirement costs that are currently recovered in rates.
No liability has been recorded with respect to lead-based paint, as the quantities of lead-based paint in the Company’s facilities are unknown. In addition, there is no incremental cost to demolitions of lead-based paint facilities vs. non-lead-based paint facilities and no regulations currently exist requiring any type of special disposal of items containing lead-based paint.
The Ludington Hydroelectric Power Plant (a jointly owned plant) has an indeterminate life and no legal obligation currently exists to decommission the plant at some future date. Substations, manholes and certain other distribution assets within Detroit Edison have an indeterminate life. Therefore, no liability has been recorded for these assets.
A reconciliation of the asset retirement obligations for 20102011 follows:
| (In millions) | ||||
| Asset retirement obligations at January 1, 2010 | $ | 1,439 | ||
| Accretion | 92 | |||
| Liabilities incurred | 10 | |||
| Liabilities settled | (9 | ) | ||
| Revision in estimated cash flows | (22 | ) | ||
| Consolidation of VIEs | 4 | |||
| Asset retirement obligations at December 31, 2010 | 1,514 | |||
| Less amount included in current liabilities | (16 | ) | ||
| $ | 1,498 | |||
| (In millions) | |||
| Asset retirement obligations at January 1, 2011 | $ | 1,514 | |
| Accretion | 93 | ||
| Liabilities incurred | 10 | ||
| Liabilities settled | (23 | ) | |
| Revision in estimated cash flows | (1 | ) | |
| Asset retirement obligations at December 31, 2011 | 1,593 | ||
| Less amount included in current liabilities | (2 | ) | |
| $ | 1,591 | ||
In 2001, Detroit Edison began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In 2011, based on management decisions revising the timing and estimate of cash flows, Detroit Edison accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management intends to suspend decommissioning activities and place the facility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations. In addition, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the Detroit Edison asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations.
Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. In 2010, Detroit Edison filed a rate case withOctober 2011, the MPSC proposingapproved Detroit Edison's request for a reduction to the nuclear
91
decommissioning surcharge under the assumption that it would request an extension of the Fermi 2 license for an additional 20 years beyond the term of the existing license which expires in 2025. Detroit Edison expects to request the license extension in 2014. This proposed extension of the license, including the associated impact on spent nuclear fuel, resulted in a revision in estimated cash flows for the Fermi 2 asset retirement obligation of approximately $22 million.$22 million. It is estimated that the cost of decommissioning Fermi 2 is $1.3$1.4 billion in 20102011 dollars and $10$10 billion in 2045 dollars, using a 6% inflation rate. In 2001, Detroit Edison began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be completed by 2012. Approximately $1.3$1.4 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.
The NRC has jurisdiction over the decommissioning of nuclear power plants and requires minimum decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost of
77
decommissioning. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.
A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and theclean-up of the Fermi site. This removal andclean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning liability. The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary. See Note 43 for additional discussion of Nuclear Decommissioning Trust Fund Assets.
NOTE 9 — DISPOSALS
Sale of Rail Services Assets
In 2010, the Company sold certain non-strategic rail services assets for gross proceeds of approximately $23 million.$23 million. The Company recognized a gain of approximately $5$5 million, net of a write-off of goodwill of approximately $4 million.$4 million.
Sale of Gathering and Processing Assets
In 2009, the Company sold certain non-strategic gas gathering and processing assets in northern Michigan for gross proceeds of approximately $45$45 million, which approximated its carrying value, including goodwill of approximately $13 million.$13 million.
NOTE 10 — OTHER IMPAIRMENTS AND RESTRUCTURING
92
Other Impairments — Barnett Shale
Our Unconventional Gas Production segment recorded pre-tax impairment losses of $10$1 million $6, $10 million and $8$6 million in 2011, 2010 2009 and 2008,2009, respectively. The impairments related primarily to the write-off of expired or expiring leasehold positions that the Company does not intend to drill.
Restructuring Costs
In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. The Company incurred CTA restructuring expense for employee severance, early retirement programs and other costs which include project management and consultant support.expense. In September 2006, the MPSC issued an order approving a settlement agreement that allowed Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provided for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-yearten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $24 million of CTA in 2008 as a regulatory asset and capitalized $2 million. The recovery of these costs for Detroit Edison was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Detroit Edison amortized prior year deferred CTA costs of $18$18 million in 2011, 2010 $18 million in 2009 and $16 million in 2008.2009. The September 2006 order did not provide a regulatory recovery mechanism for MichCon, therefore MichCon expensed CTA incurred during the period 2006 through 2008. The Company incurred restructuring expense, net of amounts deferred and capitalized of $10 million in 2008. The June 2010 MPSC order provided for MichCon’s recovery of the regulatory unamortized balance of CTA. At June 30, 2010, MichCon deferred and recognized in income approximately $32$32 million ($20 million after-tax) of previously expensed CTA. The non-pension component of CTA of approximately $21$21 million is included in Regulatory assets. The pension component of CTA of approximately $11$11 million is included in Regulatory liabilities. MichCon amortized approximately $2$3 million and $2 million of prior year deferred CTA costs in 2010.2011 and 2010, respectively. Amounts expensed are recorded in Operation and maintenance expense on the Consolidated Statements of Operations. Deferred amounts are recorded in Regulatory assets and Regulatory liabilities on the Consolidated Statements of Financial Position. See Note 12.11.
78
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
NOTE 11 — REGULATORY MATTERS |
Regulation
Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which 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 is also regulated by the FERC with respect to financing authorization and wholesale electric activities. Regulation results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses.
Regulatory Assets and Liabilities
Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Continued applicability of regulatory accounting treatment requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses and may require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.
The following are balances and a brief description of the regulatory assets and liabilities at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Assets | ||||||||
| Recoverable pension and postretirement costs: | ||||||||
| Pension | $ | 1,742 | $ | 1,670 | ||||
| Postretirement costs | 624 | 665 | ||||||
| Asset retirement obligation | 336 | 415 | ||||||
| Recoverable income taxes related to securitized regulatory assets | 400 | 476 | ||||||
| Deferred income taxes — Michigan Business Tax | 383 | 407 | ||||||
| Cost to achieve Performance Excellence Process | 137 | 136 | ||||||
| Choice incentive mechanism | 105 | — | ||||||
| Recoverable uncollectible expense | 90 | 138 | ||||||
| Other recoverable income taxes | 85 | 89 | ||||||
| Unamortized loss on reacquired debt | 65 | 70 | ||||||
| Accrued PSCR/GCR revenue | 52 | — | ||||||
| Deferred environmental costs | 41 | 40 | ||||||
| Enterprise Business Systems costs | 21 | 24 | ||||||
| Recoverable restoration expense | 19 | — | ||||||
| Electric Customer Choice implementation costs | — | 18 | ||||||
| Other | 58 | 15 | ||||||
| 4,158 | 4,163 | |||||||
| Less amount included in current assets | (100 | ) | (53 | ) | ||||
| $ | 4,058 | $ | 4,110 | |||||
| Securitized regulatory assets | $ | 729 | $ | 870 | ||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Assets | |||||||
| Recoverable pension and postretirement costs: | |||||||
| Pension | $ | 2,208 | $ | 1,742 | |||
| Postretirement costs | 778 | 624 | |||||
| Asset retirement obligation | 420 | 336 | |||||
| Recoverable Michigan income taxes | 324 | 383 | |||||
| Recoverable income taxes related to securitized regulatory assets | 316 | 400 | |||||
| Choice incentive mechanism | 166 | 105 | |||||
| Accrued PSCR/GCR revenue | 147 | 52 | |||||
| Cost to achieve Performance Excellence Process | 116 | 137 | |||||
| Other recoverable income taxes | 81 | 85 | |||||
| Unamortized loss on reacquired debt | 64 | 65 | |||||
| Recoverable restoration expense | 58 | 19 | |||||
| Deferred environmental costs | 49 | 41 | |||||
| Recoverable uncollectible expense | 42 | 90 | |||||
| Enterprise Business Systems costs | 18 | 21 | |||||
| Recoverable revenue decoupling | 18 | 5 | |||||
| Other | 48 | 53 | |||||
| 4,853 | 4,158 | ||||||
| Less amount included in current assets | (314 | ) | (100 | ) | |||
| $ | 4,539 | $ | 4,058 | ||||
| Securitized regulatory assets | $ | 577 | $ | 729 | |||
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Liabilities | ||||||||
| Asset removal costs | $ | 479 | $ | 506 | ||||
| Deferred income taxes — Michigan Business Tax | 418 | 423 | ||||||
| Negative pension offset | 129 | 133 | ||||||
| Renewable energy | 125 | 32 | ||||||
| Refundable income taxes | 77 | 88 | ||||||
| Refundable self implemented rates | 52 | 27 | ||||||
| Refundable revenue decoupling | 47 | — | ||||||
| Refundable costs under PA 141 | 33 | 27 | ||||||
| Refundable restoration expense | 15 | 15 | ||||||
| Accrued PSCR/GCR refund | 8 | 39 | ||||||
| Fermi 2 refueling outage | 3 | 13 | ||||||
| Pension equalization mechanism | — | 75 | ||||||
| Other | 36 | 11 | ||||||
| 1,422 | 1,389 | |||||||
| Less amount included in current liabilities | (94 | ) | (52 | ) | ||||
| $ | 1,328 | $ | 1,337 | |||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Liabilities | |||||||
| Asset removal costs | $ | 419 | $ | 479 | |||
| Refundable Michigan income taxes | — | 418 | |||||
| Renewable energy | 192 | 125 | |||||
| Refundable revenue decoupling | 127 | 47 | |||||
| Negative pension offset | 120 | 129 | |||||
| Refundable income taxes | 66 | 77 | |||||
| Energy Optimization | 34 | 27 | |||||
| Refundable uncollectible expense | 31 | — | |||||
| Accrued PSCR/GCR refund | 26 | 8 | |||||
| Low Income Energy Efficiency Fund | 26 | — | |||||
| Fermi 2 refueling outage | 23 | 3 | |||||
| Refundable self implemented rates | 1 | 52 | |||||
| Refundable costs under PA 141 | — | 33 | |||||
| Refundable restoration expense | — | 15 | |||||
| Other | 8 | 9 | |||||
| 1,073 | 1,422 | ||||||
| Less amount included in current liabilities | (54 | ) | (94 | ) | |||
| $ | 1,019 | $ | 1,328 | ||||
As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in Detroit Edison or MichCon’s rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.
ASSETS
Recoverable pension and postretirement costs — Accounting rules for pension and other postretirement benefit costs require, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Detroit Edison and MichCon record the impact of actuarial gains or losses and prior services costs as a Regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement costs. The asset will reverse as the deferred items are amortized and recognized as components of net periodic benefit costs. (1)
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Asset retirement obligation — This obligation is primarily for Fermi 2 decommissioning costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1)
Recoverable Michigan income taxes— In July 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. In May 2011, the MBT was repealed and the Michigan Corporate Income Tax (MCIT) was enacted. The regulatory asset was remeasured to reflect the impact of the MCIT tax rate. (1)
Recoverable income taxes related to securitized regulatory assets — Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax over a fourteen-year period ending 2015.
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Choice incentive mechanism(Continued) (CIM) — Detroit Edison receivable for non-fuel revenues lost as a result of fluctuations in electric Customer Choice sales. The CIM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.
Accrued PSCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.
Accrued GCR revenue — Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.
Cost to achieve Performance Excellence Process (PEP) — The MPSC authorized the deferral of costs to implement the PEP. These costs consist of employee severance, project management and consultant support. These costs are amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred.
Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes and amounts previously reflected in Detroit Edison’s rates. This asset will reverse over the remaining life of the related plant. (1)
Unamortized loss on reacquired debt — The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.
Recoverable restoration expense — Receivable for the MPSC approved restoration expense tracking mechanism that tracks the difference between actual restoration expense and the amount provided for in base rates, recognized pursuant to the MPSC authorization. The restoration expense tracking mechanism was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.
Deferred environmental costs — The MPSC approved the deferral of investigation and remediation costs associated with Gas Utility’s former MGP sites. Amortization of deferred costs is over a ten-year period beginning in the year after costs were incurred, with recovery (net of any insurance proceeds) through base rate filings.
Recoverable uncollectible expense (UETM) — Detroit Edison and MichCon receivable for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison.
Enterprise Business Systems (EBS) costs — The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed.
Recoverable revenue decoupling — Amounts recoverable from Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts recoverable from MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC.
Securitized regulatory assets — The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015.
(1) Regulatory assets not earning a return.
LIABILITIES
Asset removal costs — The amount collected from customers for the funding of future asset removal activities.
Refundable Michigan income taxes — In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established for the Company’s utilities, and offsetting regulatory liabilities were recorded as the
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impacts of the deferred tax assets will be reflected in rates. In May 2011, the MBT was repealed and the MCIT was enacted. The state deferred tax assets were eliminated under the MCIT and related regulatory liabilities were remeasured to zero.
Renewable energy —(Continued) Amounts collected in rates in excess of renewable energy expenditures.
Refundable revenue decoupling — Amounts refundable to Detroit Edison customers for the change in revenue resulting from the difference between actual average sales per customer compared to the base level of average sales per customer established by the MPSC. Amounts refundable to MichCon customers for the change in revenue resulting from the difference in weather-adjusted average sales per customer compared to the base level of average sales per customer established by the MPSC.
Negative pension offset — MichCon’s negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent MichCon’s pension expense is positive in future years. Refundable income taxes — Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization. Energy Optimization (EO) - The EO plan application is designed to help each customer class reduce their electric usage by: 1) building customer awareness of energy efficiency options and 2) offering a diverse set of programs and participation options that result in energy savings for each customer class. Refundable uncollectible expense (UETM )— Detroit Edison and MichCon liability for the MPSC approved uncollectible expense tracking mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. The UETM was terminated in the October 20, 2011 MPSC order issued to Detroit Edison. Accrued PSCR refund — Liability for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism. Accrued GCR refund — Liability for the temporary over-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism. Low Income Energy Efficiency Fund (LIEEF) — Escrow of LIEEF funds collected by Detroit Edison and MichCon as ordered by the MPSC pursuant to July 2011 Michigan Court of Appeals decision. Fermi 2 refueling outage — Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization. Refundable self implemented rates — Amounts refundable to customers for base rates implemented by Detroit Edison and MichCon in excess of amounts authorized in MPSC orders. Refundable costs under PA 141 — Detroit Edison’s 2007 CIM reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received that exceed the regulatory asset balances are required to be refunded to the affected classes. Refundable restoration expense — Amounts refundable for the MPSC approved restoration expense | ||
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On January 11, 2010,October 20, 2011, the MPSC issued an order in Detroit Edison’s January 26, 2009Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $217$175 million or a 4.8% increase in Detroit Edison’s annual revenue requirement for 2010.. Included in the approved increase in revenues was a return on equity of 11%10.5% on an expected permanent capital structure of 49% equity and 51% debt capital structure. In addition, the order provided for continued application of adjustment mechanisms for electric Customer Choice sales and expenses associated with restoration costs (storm and non-storm) and line clearance expenses and implementation of RDM and UETM mechanisms.
Other key aspects of the October 20, 2011 MPSC order include the following:
adopt a new Revenue Decoupling Mechanism (RDM) effective April 1, 2012, that will compare actual revenue (excluding the impacts of weather) by rate class with the base established in this rate case. The RDM has an annual collar of 1.5% in the first year and 3% in the second and subsequent years. The RDM established in the previous rate case, which considered the impact of weather, was terminated effective October 31, 2011. Therefore, there will be no RDM in place from November 2011 through March 2012;
recognition of the expiration of a wholesale contract. Since the expiration of the wholesale contract was not until December 31, 2011, the MPSC required Detroit Edison to calculate a customer credit for each kWh sold under the wholesale contract from October 29, 2011 through December 31, 2011, with the credit to be applied in its next PSCR reconciliation;
the Restoration Expense Tracking Mechanism, Line Clearance Recovery Mechanism, Uncollectible Expense Tracking Mechanism and CIM are terminated as of the date of the order;
due to uncertainty resulting from the Michigan Court of Appeals overturning collection of the Low Income Energy Efficiency Fund (LIEEF), the MPSC required the continued collection of LIEEF amounts in base rates and placement into escrow pending further orders by the MPSC;
approval of Detroit Edison's proposal to reduce the Nuclear Decommissioning Surcharge by approximately $20 million annually; and
implementation of lower depreciation rates previously approved in a June 2011 MPSC order.
2009 Detroit Edison Depreciation Filing
In compliance with an MPSC order, Detroit Edison filed a depreciation case in November 2009. On June 16, 2011, the MPSC issued an order authorizing this refund to be applied as credits to customer bills during the January 2011 billing period.reducing Detroit Edison has a refund liability of approximately $27 million, including interest at December 31, 2010 representing the refund due customers.
In August 2010, Detroit Edison filed its reconciliation for the 2009 plan year indicating that the 2009 actual renewable plan revenues and costs approximated the related surcharge revenues and cost of the filed plan. An MPSC order is expected in the first quarter of 2012.
In June 2011, Detroit Edison filed an amended REP with the MPSC requesting authority to continue to recover approximately $100 million of surcharge revenues. The proposed revenues are necessary in order to continue to properly implement Detroit Edison's 20-year REP, to deliver cleaner, renewable electric generation to its customers, to further diversify Detroit Edison's and the State of Michigan's sources of electric supply, and to address the state and national goals of increasing energy independence. On December 20, 2011, the MPSC issued an order approving the amended REP and authorizing the continuation of the surcharges.
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In August 2011, Detroit Edison filed its reconciliation for the 2010 plan year indicating that the 2010 actual renewable plan revenues and costs approximated the related surcharge revenues and cost of the filed plan. An MPSC order is expected in the third quarter of 2011.2012.
Energy Optimization (EO) Plans
In March 2009,April 2011, Detroit Edison and MichCon filed separate applications for approval of their respective reconciliations of their 2010 EO plan expenses. Specifically, Detroit Edison's EO reconciliation includes a cumulative $21 million net over-recovery at year end 2010 for the 2010 EO plan. MichCon's EO reconciliation includes a cumulative $5.6 million net over-recovery at year end 2010 for the 2010 EO plan. In November 2011, the MPSC approved settlement agreements for Detroit Edison and MichCon which authorized the over-recovery balances be included in the 2011 reconciliations.
In September 2011, Detroit Edison and MichCon filed biennial EO Plans with the MPSC as required under Michigan Public Act 295 of 2008. The EO Plan applications are designed to help each customer class reduce their electric and gas usage by: (1) building customer awareness of energy efficiency options and (2) offering a diverse set of programs and participation options that result in energy savings for each customer class. In March 2010,required. Detroit Edison and MichCon filed amended EO Plans with the MPSC. Detroit Edison’s amendedEdison's EO Plan application proposed the recovery of EO expenditures for the period2010-2015 2012-2015 of $406$294 million and further requested approval of surcharges to recover these costs, including a financial incentive mechanism. MichCon’s amendedcosts. MichCon's EO Plan application proposed the recovery of EO expenditures for the period2010-2015 2012-2015 of $150$103 million and further requested approval of surcharges that are designed to recover these costs, including a financial incentive mechanism. The MPSC approved the amended EO Plans and the surcharge and tariff sheets reflecting the exclusion of the financial incentive mechanism. The disposition of the financial incentive mechanisms is expected to be addressed in the EO reconciliation cases. In April 2010, Detroit Edison and MichCon filed reconciliations for the 2009 plan years. The Detroit Edison
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costs.
Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (LCT) Reconciliation
In March 2010, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2009 RETM and LCT. The Company’sCompany's 2009 restoration and line clearance expenses arewere less than the amount provided in rates. Accordingly, Detroit Edison has proposed a refund of approximately $16 million, including interest. On May 10, 2011, the MPSC issued an order approving the proposed refund and Detroit Edison began applying credits to customer bills in July 2011.
In March 2011, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2010 RETM and LCT. The Company's 2010 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested recovery of $19.5 million. In October 2011, the MPSC approved a settlement agreement reconciling the RETM and approving the LCT report. The MPSC authorized surcharges to recover $19.5 million over a three-month period beginning November 1, 2011.
In January 2012, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2011 RETM and LCT. The Company's 2011 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested net recovery of approximately $44 million.
Detroit Edison Revenue Decoupling Mechanism (RDM)
In May 2011, Detroit Edison filed an application with the MPSC for approval of its initial pilot RDM reconciliation for the period February 2010 through January 2011, requesting authority to refund to customers approximately $56 million, plus interest. This amount was accrued by Detroit Edison at December 31, 2011. There are various interpretations and alternative calculation methodologies relating to the pilot RDM refund calculation that could ultimately be adopted by the MPSC which may result in a range of customer refund amounts from $56 million to $140 million for this initial reconciliation filing under the pilot RDM.
In addition, Detroit Edison has accrued a pilot RDM liability for February 2011 through October 2011 of approximately $71 million, plus interest. Detroit Edison terminated the pilot RDM effective October 2011, and has requested a rehearing on this issue asserting that for reconciliation purposes, the pilot RDM should have been considered terminated in April 2011, when the Detroit Edison self-implemented rates, consistent with prior MPSC orders. An April 2011 termination would result in a decrease to the liability. However, there can be no assurance that Detroit Edison will prevail in this matter. Similar to the initial reconciliation case, there are various interpretations and alternative calculation methodologies that could be adopted which may result in a range of refund obligations in excess of the amount accrued. Considering these variables, the potential customer refund amount could range from $10 million to $130 million for the second and final pilot RDM period.
The primary uncertainties involved in the calculation methodologies of the pilot RDM for both reconciliation periods include customer class groupings and treatment of fixed customer charges. The Company believes that the calculation methodology used and the resulting refund estimates recorded follow the requirements and intent of the MPSC orders and represent the most probable amount of approximately $16 million, including interest.Detroit Edison's pilot RDM refund liability as of December 31, 2011. An MPSC order on the initial filing is expected in the second quarterfirst half of 2011.2012. Detroit Edison is required to file an application with the MPSC for
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approval of its RDM reconciliation for the period February 2011 through October 2011 by May 2012. A newly designed RDM will be in effect beginning April 2012.
Detroit Edison Uncollectible ExpenseTrue-Up Mechanism (UETM)
In March 2010,2011, Detroit Edison filed an application with the MPSC for approval of its UETM for 20092010 requesting recovery ofauthority to refund approximately $4.5$7 million consisting of costs related to 20092010 uncollectible expense and associated carrying charges.expense. In August 2010,2011, the MPSC determined thatapproved a settlement agreement for the 2010 UETM was effective with its January 2010 order in Detroit Edison’s rate case and dismissed the request for UETM expenses for 2009.authorizing a refund of approximately $7 million to be applied as credits to customer bills beginning September 1, 2011.
Detroit Edison Regulatory Asset Recovery Surcharge (RARS) ReconciliationChoice Incentive Mechanism (CIM)
In April 2010,March 2011, Detroit Edison filed an application with the MPSC for approval of the finalits CIM reconciliation for 2010 requesting recovery of its RARS.approximately $105 million. On January 20,December 6, 2011, the MPSC issued an orderapproved a settlement agreement for the 2010 CIM authorizing a refundsurcharges of approximately $28$105 million including interest, effective on a service rendered basis for the 12-month period beginning January 1, 2012.
On January 17, 2012, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for the period from January 1, 2011 through October 28, 2011. The termination date of the CIM pursuant to bethe October 20, 2011 MPSC rate order is October 20, 2011. Detroit Edison requested recovery of approximately $73 million, net of the self implementation credit applied as credits to customer bills during the February 2011 billing period.per MPSC order.
Power Supply Cost Recovery Proceedings
The PSCR process is designed to allow Detroit Edison to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. Detroit Edison’sEdison's power supply costs include fuel and related transportation costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, urea costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.
2011 Plan Year — - In September 2010, Detroit Edison filed its 2011 PSCR plan case seeking approval of a levelized PSCR factor of 2.98 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.2 billion.$1.2 billion. The plan also includes approximately $36$36 million for the recovery of its projected 2010 PSCR under-recovery. An MPSC order was issued on December 6, 2011 approving the 2011 PSCR.
2012 Plan Year - In September 2011, Detroit Edison filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected 2011 PSCR under-recovery.
Low Income Energy Efficiency Fund
The Customer Choice and Electricity Reliability Act of 2000 authorized the creation of the LIEEF administered by the MPSC. The purpose of the fund is to provide shut-off and other protection for low income customers and to promote energy efficiency by all customer classes. Detroit Edison and MichCon collect funding for the LIEEF as part of their base rates and remit the funds to the State of Michigan monthly. In July 2011, the Michigan Court of Appeals issued a decision reversing the portion of MichCon's June 2010 MPSC rate order that permitted MichCon to recover funding for the LIEEF in base rates. In response to the Court of Appeals decision, Detroit Edison and MichCon ceased remitting payments for LIEEF funding to the State of Michigan. In October 2011, the MPSC issued orders directing Detroit Edison and MichCon to continue collecting funds for LIEEF in rates and to escrow the collected funds pending further order by the MPSC. On January 26, 2012, the MPSC issued an order directing Detroit Edison and MichCon to file comprehensive plans by March 1, 2012 for refunding
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previously escrowed LIEEF funds of $(Continued)23 million and $3 million, respectively. On December 20, 2011, The Vulnerable Household Warmth Fund (VHWF) was created under Michigan law. The purpose of the fund is to provide payment or partial payment of bills for electricity, natural gas, propane, heating oil, or any other type of fuel used to heat the primary residence of a vulnerable customer during the 2011-2012 heating season. Effective with the new law, Detroit Edison and MichCon are to contribute the amounts collected in their base rates, previously remitted for the LIEEF, to the new VHWF. The monthly payments into the VHWF will cease on the earlier of September 30, 2012 or when $48 million has been is accumulated in the fund from payments by major Michigan electric and gas utilities.
MichCon filed a rate case on July 27, 2010 based on a fully projected 2011 test year. The filing with the MPSC requested a $51 million increase in revenues. During the pendency of this proceeding, MichCon continuously evaluated its case and determined that it no longer desired to pursue the relief requested. On December 13, 2010, the MPSC approved MichCon’s request to withdraw this rate filing.UETM
In March 2010,2011, MichCon filed an application with the MPSC for approval of its UETM for 20092010 requesting recovery of approximately $59$31 million, consisting of $51$7 million of costs related to 20092010 uncollectible expense and associated carrying charges and $8$24 million of under-collections for related to the 2007 UETM. On December 21, 2010,2008 UETM under-collection. In September 2011, the MPSC approved MichCon’s requesta settlement agreement approving the 2010 UETM and the implementation of a surcharge beginning October 1, 2011.
MichCon Revenue Decoupling Mechanism (RDM)
In September 2011, MichCon filed an application with new surcharges applicable to services rendered beginning on Januarythe MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. MichCon's RDM application proposed the recovery of approximately $20 million.
Gas Cost Recovery Proceedings
The GCR process is designed to allow MichCon to recover all of its gas supply costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.
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2010-2011 Plan Year — - In December 2009,June 2011, MichCon filed its 2010-2011 GCR plan year reconciliation case forcalculating a net over-recovery of $1 million, including interest. This over-recovery does not reflect the2010-2011 GCR December 6, 2011 MPSC order on the 2009-2010 plan year. The MPSC issued an order in this case in September 2010 authorizing MichCon to charge a maximum of $7.06 per Mcf, adjustable monthly by a contingent factor. The MPSC also approved MichCon’s proposed fixed price gas purchasing program and provided clarification regarding treatment of certain affiliate purchases.year reconciliation case.
2011-2012 Plan Year — - In December 2010, MichCon filed its GCR plan case for the2011-2012 GCR plan year. MichCon filed for a maximum base GCR factor of $5.89$5.89 per Mcf adjustable monthly by a contingency factor.
2012-2013 Plan Year - In December 2011, MichCon filed its GCR plan case for the 2012-2013 GCR plan year. MichCon filed for a maximum base GCR factor of $5.18 per Mcf adjustable monthly by a contingency factor.
Gas Main Renewal and Gas Meter Move Out Programs
The June 3, 2010 MPSC gas rate case order required MichCon to make filings related to gas main renewal and meter move-out programs. In a July 30, 2010 filing, MichCon proposed to implement a10-year10-year gas main renewal program beginning in 2012 which would require capital expenditures of approximately $17$17 million per year for renewing gas distribution mains, retiring gas mains, and where appropriate and when related to the gas main renewal or retirement activity, relocate inside meters to outside locations and renew service lines.
In a September 30, 2010 filing, MichCon proposed to implement a10-year10-year gas meter move out program beginning in 2012 which would require capital expenditures of approximately $22$22 million per year primarily for relocation of inside meters to the outside of residents’residents' houses. RecoveryIn September 2011, the MPSC issued orders approving both programs and requested MichCon to include the recovery of costs associated with these two programs is expected to be provided through these filings orin future MichCon rate cases.
Other
The Company is unable to predict the outcome of the unresolved regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders and appeals, which may materially impact the financial position, results of operations and cash flows of the Company.
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Table of Contents |
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
NOTE 12 — INCOME TAXES
Income Tax Summary
The Company files a consolidated federal income tax return. Total income tax expense varied from the statutory federal income tax rate for the following reasons:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Income before income taxes | $ | 950 | $ | 782 | $ | 819 | ||||||
| Income tax expense at 35% statutory rate | $ | 333 | $ | 274 | $ | 287 | ||||||
| Production tax credits | (33 | ) | (12 | ) | (7 | ) | ||||||
| Investment tax credits | (6 | ) | (7 | ) | (7 | ) | ||||||
| Depreciation | (4 | ) | (4 | ) | (4 | ) | ||||||
| Employee Stock Ownership Plan dividends | (5 | ) | (5 | ) | (4 | ) | ||||||
| Medicare part D subsidy | — | (6 | ) | (5 | ) | |||||||
| Domestic production activities deduction | (7 | ) | (5 | ) | (2 | ) | ||||||
| Goodwill attributed to the sale of Gas Utility subsidiaries | — | 4 | — | |||||||||
| Settlement of Federal tax audit | (12 | ) | (11 | ) | — | |||||||
| State and local income taxes, net of federal benefit | 44 | 25 | 23 | |||||||||
| Other, net | 1 | (6 | ) | 7 | ||||||||
| Income tax expense from continuing operations | $ | 311 | $ | 247 | $ | 288 | ||||||
| Effective income tax rate | 32.7 | % | 31.6 | % | 35.2 | % | ||||||
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| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Income before income taxes | $ | 987 | $ | 950 | $ | 782 | |||||
| Income tax expense at 35% statutory rate | $ | 345 | $ | 333 | $ | 274 | |||||
| Production tax credits | (6 | ) | (33 | ) | (12 | ) | |||||
| Investment tax credits | (6 | ) | (6 | ) | (7 | ) | |||||
| Depreciation | (4 | ) | (4 | ) | (4 | ) | |||||
| Employee Stock Ownership Plan dividends | (4 | ) | (5 | ) | (5 | ) | |||||
| Medicare part D subsidy | — | — | (6 | ) | |||||||
| Domestic production activities deduction | (7 | ) | (7 | ) | (5 | ) | |||||
| Goodwill attributed to the sale of Gas Utility subsidiaries | — | — | 4 | ||||||||
| Settlement of Federal tax audit | — | (12 | ) | (11 | ) | ||||||
| State and local income taxes, net of federal benefit | 37 | 44 | 25 | ||||||||
| Enactment of Michigan Corporate Income Tax, net of federal expense | (87 | ) | — | — | |||||||
| Other, net | (1 | ) | 1 | (6 | ) | ||||||
| Income tax expense | $ | 267 | $ | 311 | $ | 247 | |||||
| Effective income tax rate | 27.1 | % | 32.7 | % | 31.6 | % | |||||
Components of income tax expense were as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Continuing operations | ||||||||||||
| Current income taxes | ||||||||||||
| Federal | $ | (172 | ) | $ | 25 | $ | 130 | |||||
| State and other income tax expense | 26 | 17 | 17 | |||||||||
| Total current income taxes | (146 | ) | 42 | 147 | ||||||||
| Deferred income taxes | ||||||||||||
| Federal | 415 | 182 | 121 | |||||||||
| State and other income tax expense | 42 | 23 | 20 | |||||||||
| Total deferred income taxes | 457 | 205 | 141 | |||||||||
| Total income taxes from continuing operations | 311 | 247 | 288 | |||||||||
| Discontinued operations | — | — | 12 | |||||||||
| Total | $ | 311 | $ | 247 | $ | 300 | ||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Current income tax expense (benefit) | |||||||||||
| Federal | $ | 25 | $ | (172 | ) | $ | 25 | ||||
| State and other income tax | 22 | 26 | 17 | ||||||||
| Total current income taxes | 47 | (146 | ) | 42 | |||||||
| Deferred income tax expense (benefit) | |||||||||||
| Federal | 318 | 415 | 182 | ||||||||
| State and other income tax | (98 | ) | 42 | 23 | |||||||
| Total deferred income taxes | 220 | 457 | 205 | ||||||||
| Total | $ | 267 | $ | 311 | $ | 247 | |||||
Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences. Consistent with rate making treatment, deferred taxes are offset in the table below for temporary differences which have related regulatory assets and liabilities.
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Deferred tax assets (liabilities) were comprised of the following at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| Property, plant and equipment | $ | (2,558 | ) | $ | (1,932 | ) | ||
| Securitized regulatory assets | (396 | ) | (474 | ) | ||||
| Alternative minimum tax credit carry-forwards | 337 | 197 | ||||||
| Merger basis differences | 49 | 51 | ||||||
| Pension and benefits | (36 | ) | 17 | |||||
| Other comprehensive income | 83 | 75 | ||||||
| Derivative assets and liabilities | 29 | 59 | ||||||
| State net operating loss and credit carry-forwards | 33 | 43 | ||||||
| Other | (2 | ) | 78 | |||||
| (2,461 | ) | (1,886 | ) | |||||
| Less valuation allowance | (32 | ) | (43 | ) | ||||
| $ | (2,493 | ) | $ | (1,929 | ) | |||
| Current deferred income tax assets | $ | 139 | $ | 167 | ||||
| Long-term deferred income tax liabilities | (2,632 | ) | (2,096 | ) | ||||
| $ | (2,493 | ) | $ | (1,929 | ) | |||
| Deferred income tax assets | $ | 1,418 | $ | 1,462 | ||||
| Deferred income tax liabilities | (3,911 | ) | (3,391 | ) | ||||
| $ | (2,493 | ) | $ | (1,929 | ) | |||
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| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Property, plant and equipment | $ | (3,131 | ) | $ | (2,558 | ) | |
| Securitized regulatory assets | (360 | ) | (396 | ) | |||
| Alternative minimum tax credit carry-forwards | 294 | 337 | |||||
| Merger basis differences | 50 | 49 | |||||
| Pension and benefits | (39 | ) | (36 | ) | |||
| Other comprehensive income | 99 | 83 | |||||
| Derivative assets and liabilities | 64 | 29 | |||||
| State net operating loss and credit carry-forwards | 30 | 33 | |||||
| Other | (45 | ) | (2 | ) | |||
| (3,038 | ) | (2,461 | ) | ||||
| Less valuation allowance | (27 | ) | (32 | ) | |||
| $ | (3,065 | ) | $ | (2,493 | ) | ||
| Current deferred income tax assets | $ | 51 | $ | 139 | |||
| Long-term deferred income tax liabilities | (3,116 | ) | (2,632 | ) | |||
| $ | (3,065 | ) | $ | (2,493 | ) | ||
| Deferred income tax assets | $ | 1,048 | $ | 1,418 | |||
| Deferred income tax liabilities | (4,113 | ) | (3,911 | ) | |||
| $ | (3,065 | ) | $ | (2,493 | ) | ||
Production tax credits earned in prior years but not utilized totaled $337$294 million and are carried forward indefinitely as alternative minimum tax credits. The majority of the production tax credits earned, including all of those from our synfuel projects, were generated from projects that had received a private letter ruling (PLR) from the Internal Revenue Service (IRS). These PLRs provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.
The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated Statements of Financial Position. Investment tax credits are deferred and amortized to income over the average life of the related property.
The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $32$30 million and $43$33 million at December 31, 20102011 and 2009,2010, respectively. The state net operating loss and credit carry-forwards expire from 20112012 through 2030.2031. The Company has recorded valuation allowances at December 31, 20102011 and 20092010 of approximately $32$27 million and $43$32 million, respectively, with respect to these deferred tax assets. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
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Uncertain Tax Positions
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Balance at January 1 | $ | 81 | $ | 72 | $ | 22 | ||||||
| Additions for tax positions of prior years | 4 | 15 | 12 | |||||||||
| Reductions for tax positions of prior years | (4 | ) | (5 | ) | (5 | ) | ||||||
| Additions for tax positions related to the current year | — | 7 | 47 | |||||||||
| Settlements | (53 | ) | (5 | ) | (1 | ) | ||||||
| Lapse of statute of limitations | — | (3 | ) | (3 | ) | |||||||
| Balance at December 31 | $ | 28 | $ | 81 | $ | 72 | ||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Balance at January 1 | $ | 28 | $ | 81 | $ | 72 | |||||
| Additions for tax positions of prior years | 27 | 4 | 15 | ||||||||
| Reductions for tax positions of prior years | (4 | ) | (4 | ) | (5 | ) | |||||
| Additions for tax positions related to the current year | 1 | — | 7 | ||||||||
| Settlements | (3 | ) | (53 | ) | (5 | ) | |||||
| Lapse of statute of limitations | (1 | ) | — | (3 | ) | ||||||
| Balance at December 31 | $ | 48 | $ | 28 | $ | 81 | |||||
The Company had $5$4 million and $7$5 million of unrecognized tax benefits at December 31, 2011 and at December 31, 2010 and at December 31, 2009,, respectively, that, if recognized, would favorably impact its effective tax rate. During the next twelve months, it is reasonably possible that the Company will settle certain federal and state tax examinations and audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $13$31 million within the next twelve months.
The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $3$2 million and $6$3 million at December 31, 2011 and December 31, 2010 and December 31, 2009,, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $1$(2) million $(2), $1 million and $2$(2) million in 2011, 2010 and 2009, and 2008, respectively.
Michigan Corporate Income Tax (MCIT)
On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and became effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.
As a result of the enactment of the MCIT, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $36 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT. Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of the net deferred tax assets of $308 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $87 million decrease in deferred tax liabilities attributable to our non-utilities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $87 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy's unitary Michigan tax return and was recognized as a reduction to income tax expense in 2011.
Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statement of Cash Flows.
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NOTE 13 — COMMON STOCK
Common Stock
In March 2010, the Company contributed $100$100 million of DTE Energy common stock to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust. The common stock was contributed over four business days from March 26, 2010 through March 31, 2010 and was valued using the closing market prices of DTE Energy common stock on each of those days in accordance with fair value measurement and accounting requirements.
Under the DTE Energy Company Long-Term Incentive Plan, the Company grants non-vested stock awards to key employees, primarily management. As a result of a stock award, a settlement of an award of performance shares, or by exercise of a participant’s stock option, the Company may deliver common stock from the Company’s authorized but unissued common stockand/or from outstanding common stock acquired by or on behalf of the Company in the name of the participant.
Dividends
Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a total funded debt to capitalization ratio, as defined in the agreements, of no more than 0.65 to 1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. See Note 1817 for a definition of this ratio. The effect of this provision as of December 31, 2011 and December 31, 2010 was to restrict the payment of approximately $46$128 million and $46 million, respectively, of total retained earnings of approximately $3.4 billion.$3.75 billion and $3.4 billion, respectively. There are no other effective limitations with respect to the Company’s ability to pay dividends.
90 NOTE 14 — EARNINGS PER SHARE |
The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options. Effective January 1, 2009, the adoption of new accounting requirements clarifying the definition of participating securities to be included in the earnings per share calculation had the effect of reducing previously
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| 2010 | 2009 | 2008 | ||||||||||
| (In millions, expect per share amounts) | ||||||||||||
Basic Earnings per Share | ||||||||||||
| Net income attributable to DTE Energy Company | $ | 630 | $ | 532 | $ | 546 | ||||||
| Average number of common shares outstanding | 168 | 164 | 163 | |||||||||
| Weighted average net restricted shares outstanding | 1 | 1 | 1 | |||||||||
| Dividends declared — common shares | $ | 365 | $ | 347 | $ | 344 | ||||||
| Dividends declared — net restricted shares | 2 | 2 | 2 | |||||||||
| Total distributed earnings | $ | 367 | $ | 349 | $ | 346 | ||||||
| Net income less distributed earnings | $ | 263 | $ | 183 | $ | 200 | ||||||
| Distributed (dividends per common share) | $ | 2.18 | $ | 2.12 | $ | 2.12 | ||||||
| Undistributed | 1.57 | 1.12 | 1.22 | |||||||||
| Total Basic Earnings per Common Share | $ | 3.75 | $ | 3.24 | $ | 3.34 | ||||||
Diluted Earnings per Share | ||||||||||||
| Net income attributable to DTE Energy Company | $ | 630 | $ | 532 | $ | 546 | ||||||
| Average number of common shares outstanding | 168 | 164 | 163 | |||||||||
| Average incremental shares from assumed exercise of options | 1 | — | — | |||||||||
| Common shares for dilutive calculation | 169 | 164 | 163 | |||||||||
| Weighted average net restricted shares outstanding | 1 | 1 | 1 | |||||||||
| Dividends declared — common shares | $ | 365 | $ | 347 | $ | 344 | ||||||
| Dividends declared — net restricted shares | 2 | 2 | 2 | |||||||||
| Total distributed earnings | $ | 367 | $ | 349 | $ | 346 | ||||||
| Net income less distributed earnings | $ | 263 | $ | 183 | $ | 200 | ||||||
| Distributed (dividends per common share) | $ | 2.18 | $ | 2.12 | $ | 2.12 | ||||||
| Undistributed | 1.56 | 1.12 | 1.22 | |||||||||
| Total Diluted Earnings per Common Share | $ | 3.74 | $ | 3.24 | $ | 3.34 | ||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions, expect per share amounts) | |||||||||||
| Basic Earnings per Share | |||||||||||
| Net income attributable to DTE Energy Company | $ | 711 | $ | 630 | $ | 532 | |||||
| Average number of common shares outstanding | 169 | 168 | 164 | ||||||||
| Weighted average net restricted shares outstanding | 1 | 1 | 1 | ||||||||
| Dividends declared — common shares | $ | 392 | $ | 365 | $ | 347 | |||||
| Dividends declared — net restricted shares | 1 | 2 | 2 | ||||||||
| Total distributed earnings | $ | 393 | $ | 367 | $ | 349 | |||||
| Net income less distributed earnings | $ | 318 | $ | 263 | $ | 183 | |||||
| Distributed (dividends per common share) | $ | 2.32 | $ | 2.18 | $ | 2.12 | |||||
| Undistributed | 1.87 | 1.57 | 1.12 | ||||||||
| Total Basic Earnings per Common Share | $ | 4.19 | $ | 3.75 | $ | 3.24 | |||||
| Diluted Earnings per Share | |||||||||||
| Net income attributable to DTE Energy Company | $ | 711 | $ | 630 | $ | 532 | |||||
| Average number of common shares outstanding | 169 | 168 | 164 | ||||||||
| Average incremental shares from assumed exercise of options | 1 | 1 | — | ||||||||
| Common shares for dilutive calculation | 170 | 169 | 164 | ||||||||
| Weighted average net restricted shares outstanding | 1 | 1 | 1 | ||||||||
| Dividends declared — common shares | $ | 392 | $ | 365 | $ | 347 | |||||
| Dividends declared — net restricted shares | 1 | 2 | 2 | ||||||||
| Total distributed earnings | $ | 393 | $ | 367 | $ | 349 | |||||
| Net income less distributed earnings | $ | 318 | $ | 263 | $ | 183 | |||||
| Distributed (dividends per common share) | $ | 2.32 | $ | 2.18 | $ | 2.12 | |||||
| Undistributed | 1.86 | 1.56 | 1.12 | ||||||||
| Total Diluted Earnings per Common Share | $ | 4.18 | $ | 3.74 | $ | 3.24 | |||||
Options to purchase approximately 5 million shares, 4 million shares and 54 million shares of common stock in 2010 2009 and 2008,2009, respectively, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
NOTE 15 — LONG-TERM DEBT |
Long-Term Debt
The Company’s long-term debt outstanding and weighted average interest rates (1) of debt outstanding at December 31 were:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Mortgage bonds, notes, and other | ||||||||
DTE Energy Debt, Unsecured | ||||||||
| 6.9% due 2011 to 2033 | $ | 1,597 | $ | 1,597 | ||||
Detroit Edison Taxable Debt, Principally Secured | ||||||||
| 5.5% due 2011 to 2038 | 2,915 | 2,829 | ||||||
Detroit Edison Tax-Exempt Revenue Bonds(2) | ||||||||
| 5.5% due 2011 to 2038 | 1,283 | 1,263 | ||||||
MichCon Taxable Debt, Principally Secured | ||||||||
| 6.1% due 2012 to 2033 | 889 | 889 | ||||||
Other Long-Term Debt, Including Non-Recourse Debt | 195 | 180 | ||||||
| �� | 6,879 | 6,758 | ||||||
| Less amount due within one year | (765 | ) | (521 | ) | ||||
| $ | 6,114 | $ | 6,237 | |||||
Securitization bonds | ||||||||
| 6.5% due 2011 to 2015 | $ | 793 | $ | 933 | ||||
| Less amount due within one year | (150 | ) | (140 | ) | ||||
| $ | 643 | $ | 793 | |||||
Trust preferred-linked securities | ||||||||
| 7.8% due 2032 | $ | 186 | $ | 186 | ||||
| 7.5% due 2044 | 103 | 103 | ||||||
| $ | 289 | $ | 289 | |||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Mortgage bonds, notes, and other | |||||||
| DTE Energy Debt, Unsecured | |||||||
| 5.5% due 2013 to 2033 | $ | 1,298 | $ | 1,597 | |||
| Detroit Edison Taxable Debt, Principally Secured | |||||||
| 5.3% due 2012 to 2041 | 3,515 | 2,915 | |||||
| Detroit Edison Tax-Exempt Revenue Bonds (2) | |||||||
| 5.1% due 2012 to 2038 | 893 | 1,283 | |||||
| MichCon Taxable Debt, Principally Secured | |||||||
| 6.1% due 2012 to 2033 | 889 | 889 | |||||
| Other Long-Term Debt, Including Non-Recourse Debt | 165 | 195 | |||||
| 6,760 | 6,879 | ||||||
| Less amount due within one year | (355 | ) | (765 | ) | |||
| $ | 6,405 | $ | 6,114 | ||||
| Securitization bonds | |||||||
| 6.5% due 2012 to 2015 | $ | 643 | $ | 793 | |||
| Less amount due within one year | (164 | ) | (150 | ) | |||
| $ | 479 | $ | 643 | ||||
| Junior Subordinated Debentures | |||||||
| 6.5% due 2061 | $ | 280 | $ | — | |||
| Trust preferred-linked securities | |||||||
| 7.8% due 2032 | $ | — | $ | 186 | |||
| 7.5% due 2044 | — | 103 | |||||
| $ | — | $ | 289 | ||||
| (1) | Weighted average interest rates as of December 31, |
| (2) | Detroit Edison Tax-Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds. |
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92
Debt Issuances
In 2010,2011, the Company issued or remarketed the following long-term debt:
| Company | Month Issued | Type | Interest Rate | Maturity | Amount | |||||||||||
| (In millions) | ||||||||||||||||
| Detroit Edison | August | Senior Notes(1) | 3.45 | % | 2020 | 300 | ||||||||||
| Detroit Edison | September | Senior Notes(1)(2) | 4.89 | % | 2020 | 300 | ||||||||||
| Detroit Edison | December | Tax-Exempt Revenue Bonds(3) | 5.00 | % | 2030 | 20 | ||||||||||
| $ | 620 | |||||||||||||||
| Company | Month Issued | Type | Interest Rate | Maturity | Amount | ||||||||
| (In millions) | |||||||||||||
| Detroit Edison | April | Tax-Exempt Revenue Bonds (1) | 2.35 | % | 2024 | $ | 31 | ||||||
| Detroit Edison | May | Mortgage Bonds (2) | 3.90 | % | 2021 | 250 | |||||||
| DTE Energy | May | Senior Notes (3) | Variable (4) | 2013 | 300 | ||||||||
| Detroit Edison | September | Mortgage Bonds (5) | 4.31 | % | 2023 | 102 | |||||||
| Detroit Edison | September | Mortgage Bonds (5) | 4.46 | % | 2026 | 77 | |||||||
| Detroit Edison | September | Mortgage Bonds (5) | 5.67 | % | 2041 | 46 | |||||||
| Detroit Edison | September | Tax-Exempt Revenue Bonds (6) | 2.13 | % | 2030 | 82 | |||||||
| Detroit Edison | September | Mortgage Bonds (7) | 4.50 | % | 2041 | 140 | |||||||
| DTE Energy | December | Junior Subordinated Debentures (8) | 6.50 | % | 2061 | 280 | |||||||
| $ | 1,308 | ||||||||||||
(1) These bonds were remarketed for a three-year term ending April 1, 2014. The final maturity of the issue is October 1, 2024.
(2) Proceeds were used for general corporate purposes.
(3) Proceeds were used to repay a portion of DTE Energy's $600 million7.05% Senior Notes due June 1, 2011 and for general corporate purposes.
(4) The interest rate is reset quarterly at the three-month LIBOR plus 70 basis points.
(5) Proceeds were used to retire callable tax-exempt revenue bonds and for general corporate purposes.
(6) These bonds were remarketed for a five-year term ending September 1, 2016. The final maturity of the issue is September 1, 2030.
(7) Proceeds were used to retire approximately $140 million of callable tax-exempt revenue bonds and for general corporate purposes.
(8) Proceeds were used to redeem Trust Preferred-Linked Securities.
Debt Retirements and Redemptions
In 2010,2011, the following debt was retired:retired, through optional redemption or payment at maturity:
| Company | Month Retired | Type | Interest Rate | Maturity | Amount | |||||||||||||||
| (In millions) | ||||||||||||||||||||
| Detroit Edison | September | Senior Notes(1 | ) | 6.125 | % | 2010 | $ | 500 | ||||||||||||
| Company | Month Retired | Type | Interest Rate | Maturity | Amount | |||||||
| (In millions) | ||||||||||||
| Detroit Edison | May | Tax-Exempt Revenue Bonds | 6.95% | 2011 | $ | 26 | ||||||
| DTE Energy | June | Senior Notes | 7.05% | 2011 | 600 | |||||||
| Detroit Edison | September | Tax-Exempt Revenue Bonds | 5.55% | 2029 | 118 | |||||||
| Detroit Edison | September | Tax-Exempt Revenue Bonds | 5.65% | 2029 | 67 | |||||||
| Detroit Edison | September | Tax-Exempt Revenue Bonds | 5.65% | 2029 | 40 | |||||||
| Detroit Edison | September | Tax-Exempt Revenue Bonds | 5.45% | 2029 | 140 | |||||||
| DTE Energy | December | Trust Preferred-Linked Securities | 7.80% | 2032 | 186 | |||||||
| DTE Energy | December | Trust Preferred-Linked Securities | 7.50% | 2044 | 103 | |||||||
| $ | 1,280 | |||||||||||
93
The following table shows the scheduled debt maturities, excluding any unamortized discount or premium on debt:
| 2016 and | ||||||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
| Amount to mature | $ | 915 | $ | 520 | $ | 512 | $ | 861 | $ | 477 | $ | 4,685 | $ | 7,970 | ||||||||||||||
| 2012 | 2013 | 2014 | 2015 | 2016 | 2017 and Thereafter | Total | |||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||
| Amount to mature | $ | 519 | $ | 811 | $ | 892 | $ | 476 | $ | 465 | $ | 4,530 | $ | 7,693 | |||||||||||||
Junior Subordinated Debentures
In December 2011, DTE Energy has interests in various unconsolidated trusts that were formed forissued $280 million of 6.50% Junior Subordinated Debentures due 2061 with proceeds used to redeem the sole purpose of issuing preferred securities and lending the gross proceeds to the Company. The sole assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments the Company makes are used by the trusts to make cash distributions on the preferred securities it has issued.Trust Preferred-Linked Securities.
The Company has the right to extenddefer interest payment periodspayments on the debt securities. Should the Company exercise this right, it cannot declare or pay dividends on, or redeem, purchase or acquire, any of its capital stock during the deferral period. Any deferred interest payments will bear additional interest at the rate of 6.50% per year.
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Cross Default Provisions
Substantially all of the net utility properties of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit Edison or MichCon fail to timely pay their indebtedness under these mortgages, such failure may create cross defaults in the indebtedness of DTE Energy.
NOTE 16 — PREFERRED AND PREFERENCE SECURITIES
As of December 31, 2010,2011, the amount of authorized and unissued stock is as follows:
| Type of | Shares | |||||||||
| Company | Stock | Par Value | Authorized | |||||||
| DTE Energy | Preferred | None | 5,000,000 | |||||||
| Detroit Edison | Preferred | $ | 100 | 6,747,484 | ||||||
| Detroit Edison | Preference | $ | 1 | 30,000,000 | ||||||
| MichCon | Preferred | $ | 1 | 7,000,000 | ||||||
| MichCon | Preference | $ | 1 | 4,000,000 | ||||||
| Company | Type of Stock | Par Value | Shares Authorized | ||||||
| DTE Energy | Preferred | $ | — | 5,000,000 | |||||
| Detroit Edison | Preferred | $ | 100 | 6,747,484 | |||||
| Detroit Edison | Preference | $ | 1 | 30,000,000 | |||||
| MichCon | Preferred | $ | 1 | 7,000,000 | |||||
| MichCon | Preference | $ | 1 | 4,000,000 | |||||
NOTE 17 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS
In August 2010,October 2011, DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon, entered into amended and restated two-year unsecured revolving credit agreements and new three-yearfive-year unsecured revolving credit agreements with a syndicate of 2320 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.25%8.5% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.
Detroit Edison entered into a one year $40 million letter of credit facility in December 2011. The facility was terminated early in January 2012 following cancellation of the letter of credit that it supported.
The above agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1.1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain MichCon short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At December 31, 2010,2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon are 0.490.50 to 1, 0.52 to 1 and 0.460.45 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at December 31, 20102011 is shown in the following table:
| DTE Energy | Detroit Edison | MichCon | Total | |||||||||||||
| (In millions) | ||||||||||||||||
| Unsecured revolving credit facility, expiring August 2012 | $ | 538 | $ | 212 | $ | 250 | $ | 1,000 | ||||||||
| Unsecured revolving credit facility, expiring August 2013 | 562 | 63 | 175 | 800 | ||||||||||||
| Unsecured letter of credit facility, expiring in May 2013 | 50 | — | — | 50 | ||||||||||||
| Unsecured letter of credit facility, expiring in August 2015 | 125 | — | — | 125 | ||||||||||||
| Total credit facilities at December 31, 2010 | $ | 1,275 | $ | 275 | $ | 425 | $ | 1,975 | ||||||||
| Amounts outstanding at December 31, 2010: | ||||||||||||||||
| Commercial paper issuances | — | — | 150 | 150 | ||||||||||||
| Letters of credit | 153 | — | — | 153 | ||||||||||||
| 153 | — | 150 | 303 | |||||||||||||
| Net availability at December 31, 2010 | $ | 1,122 | $ | 275 | $ | 275 | $ | 1,672 | ||||||||
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94
| DTE Energy | Detroit Edison | MichCon | Total | ||||||||||||
| (In millions) | |||||||||||||||
| Unsecured letter of credit facility, expiring in December 2012 | $ | — | $ | 40 | $ | — | $ | 40 | |||||||
| Unsecured letter of credit facility, expiring in May 2013 | 50 | — | — | 50 | |||||||||||
| Unsecured letter of credit facility, expiring in August 2015 | 125 | — | — | 125 | |||||||||||
| Unsecured revolving credit facility, expiring October 2016 | 1,100 | 300 | 400 | 1,800 | |||||||||||
| Total credit facilities at December 31, 2011 | $ | 1,275 | $ | 340 | $ | 400 | $ | 2,015 | |||||||
| Amounts outstanding at December 31, 2011: | |||||||||||||||
| Commercial paper issuances | 234 | — | 185 | 419 | |||||||||||
| Letters of credit | 178 | 40 | — | 218 | |||||||||||
| 412 | 40 | 185 | 637 | ||||||||||||
| Net availability at December 31, 2011 | $ | 863 | $ | 300 | $ | 215 | $ | 1,378 | |||||||
The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $28$39 million which are used for various corporate purposes.
The weighted average interest rate for short-term borrowings was 0.4%0.5% and 0.7%0.4% at December 31, 20102011 and 2009,2010, respectively.
In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $100$100 million with its clearing agent. In April 2010, theThe agreement, wasas amended, to allowalso allows for up to $50$50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At December 31, 2010,2011, a $10$15 million letter of credit was in place, raising the capacity under this facility for up to $110 million.$115 million. The $10$15 million letter of credit is included in the table above. The amount outstanding under this agreement was $39$56 million and $1$39 million at December 31, 2011 and December 31, 2010 and December 31, 2009,, respectively.
| NOTE 18 — CAPITAL AND OPERATING LEASES |
Lessee — The Company leases various assets under capital and operating leases, including coal railcars, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2031. Future minimum lease payments under non-cancelable leases at December 31, 20102011 were:
| Capital | Operating | |||||||
| Leases | Leases | |||||||
| (In millions) | ||||||||
| 2011 | $ | 12 | $ | 39 | ||||
| 2012 | 9 | 32 | ||||||
| 2013 | 9 | 26 | ||||||
| 2014 | 9 | 22 | ||||||
| 2015 | 9 | 18 | ||||||
| Thereafter | 14 | 74 | ||||||
| Total minimum lease payments | $ | 62 | $ | 211 | ||||
| Less imputed interest | 9 | |||||||
| Present value of net minimum lease payments | 53 | |||||||
| Less current portion | 10 | |||||||
| Non-current portion | $ | 43 | ||||||
Capital Leases | Operating Leases | ||||||
| (In millions) | |||||||
| 2012 | $ | 9 | $ | 37 | |||
| 2013 | 7 | 29 | |||||
| 2014 | 9 | 24 | |||||
| 2015 | 7 | 20 | |||||
| 2016 | 3 | 18 | |||||
| Thereafter | — | 67 | |||||
| Total minimum lease payments | $ | 35 | $ | 195 | |||
| Less imputed interest | 5 | ||||||
| Present value of net minimum lease payments | 30 | ||||||
| Less current portion | 7 | ||||||
| Non-current portion | $ | 23 | |||||
Rental expense for operating leases was $54$71 million in 2011, $54 million in 2010, $58and $58 million in 2009, and $49 million in 2008.2009.
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95
| (In millions) | ||||
| 2011 | $ | 12 | ||
| 2012 | 12 | |||
| 2013 | 12 | |||
| 2014 | 12 | |||
| 2015 | 12 | |||
| Thereafter | 56 | |||
| Total minimum future lease receipts | 116 | |||
| Residual value of leased pipeline | 40 | |||
| Less unearned income | (64 | ) | ||
| Net investment in capital lease | 92 | |||
| Less current portion | (4 | ) | ||
| $ | 88 | |||
| (In millions) | |||
| 2012 | $ | 12 | |
| 2013 | 12 | ||
| 2014 | 12 | ||
| 2015 | 12 | ||
| 2016 | 12 | ||
| Thereafter | 43 | ||
| Total minimum future lease receipts | 103 | ||
| Residual value of leased pipeline | 40 | ||
| Less unearned income | (56 | ) | |
| Net investment in capital lease | 87 | ||
| Less current portion | (4 | ) | |
| $ | 83 | ||
NOTE 19 — COMMITMENTS AND CONTINGENCIES
Environmental
Electric Utility
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 mercuryother air pollution. The newThese rules will leadhave led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, mercury and mercuryother emissions. To comply with these requirements, Detroit Edison has spent approximately $1.5$1.7 billion through 2010.2011. The Company estimates Detroit Edison will make capital expenditures of over $230approximately $255 million in 20112012 and up to $2.1approximately $1.9 billion of additional capital expenditures through 20202021 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. ItThe Cross State Air Pollution Rule (CSAPR), finalized in July 2011, requires further reductions of sulfur dioxide and nitrogen oxides emissions beginning in 2012. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit granted the motions to stay the rule, leaving Detroit Edison temporarily subject to the previously existing Clean Air Interstate Rule (CAIR). The Electric Generating Unit Maximum Achievable Control Technology (EGU MACT) Rule was finalized on December 16, 2011. The EGU MACT requires reductions of mercury and other hazardous air pollutants beginning in 2015. Because these rules were recently finalized and technologies to comply are still being tested, it is not possible to quantify the impact of those expected rulemakings at this time.
these rulemakings.
In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five of Detroit Edison’sEdison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. InAn additional NOV/FOV was received in June 2010 the EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant.
On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA is requestingrequested 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 is requestingrequested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits
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for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison’sEdison's fleet of coal-fired power plants until the new control equipment is operating. In January
On August 23, 2011, the EPA’sU.S. District judge granted DTE Energy's motion for preliminary injunction was denied and the liability phase ofsummary judgment in the civil suit has been scheduled for trialcase, dismissing the case and entering judgment in May 2011.
favor of DTE Energy.On October 20, 2011, the EPA caused to be filed a Notice of Appeal. A decision by the Court of Appeals is not expected until late 2012. DTE Energy and Detroit Edison believe that the
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plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV and the result of the civil action, Detroit Edisonappeals process, the Company could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs,and/or pay fines. DTE Energy and Detroit EdisonThe Company cannot predict the financial impact or outcome of this matter, or the timing of its resolution.
Water — - In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of completed studies and expected future studies, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55$55 million in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule and in April 2009 upheld the EPA’sEPA's use of this provision in determining best technology available for reducing environmental impacts. Concurrently,The EPA published a proposed rule in 2011 that extended the EPA continuestime line to develop a revised2020 with an estimated expected increase in costs to $80 million. A final rule a draft of which is expected to be published in the first quarter of 2011, with a final rule scheduled for mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the impacts of these developing requirements.
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. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites, including the area surrounding an ash landfill, electrical distribution substations, and underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At December 31, 20102011 and December 31, 2009,2010, the Company had $9$8 million and $9 million, respectively, accrued for remediation. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows.
The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published onin June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated
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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.
Gas Utility
Contaminated Sites — Gas Utility owns, or previously owned, 15 former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.
The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of December 31, 20102011 and December 31, 2009,2010, the Company had $36$36 million, accrued for remediation.
Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial
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position and cash flows. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a ten-yearten-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens Fuel Gas approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s results of operations.
Non-Utility
The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants.
The Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a Notice of ViolationNOV in June of 2007 alleging potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDNREMDEQ concerning visible emissions readings that resulted from the Company self reporting to MDNREMDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the impact of this investigation.
In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is also in the process of settling historicalnegotiating a Consent Order with the EPA to settle these historic air and water violations at its coke battery facility located in Pennsylvania. At this time,issues. The Company expects to enter into the Company cannot predictConsent Order during the impactfirst quarter of this settlement. 2012.
The Company received two noticesNotices of violationViolation from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend approximately $0.7less than $1 million on the existing waste water treatment system to comply with existing water discharge requirements.requirements and to upgrade its coal pile storm water runoff management program. The Company may spend an additional $13$13 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.
The Company’sCompany believes that its non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.
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Other
In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). The effective dates of the major source IBMACT and CISWI regulations were stayed anda re-proposal was issued by the EPA in December 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Based on the final approved regulations, anticipated in the first half of 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.
In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400$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.
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Nuclear Operations
Property Insurance
Detroit Edison maintains property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of the insurance policies.
Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. This policy has a 12-week12-week waiting period and provides an aggregate $490$490 million of coverage over a three-yearthree-year period.
Detroit Edison has $500$500 million in primary coverage and $2.25$2.25 billion of excess coverage for stabilization, decontamination, debris removal, repairand/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.$2.75 billion.
In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was extended through December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts. For multiple terrorism losses caused by acts of terrorism not covered under the TRIA occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2$3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.
Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $28$29 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.
Public Liability Insurance
As of January 1, 2011,2012, as required by federal law, Detroit Edison maintains $375$375 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million.$300 million. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $117.5$117.5 million could be levied against each licensed nuclear facility, but not more than $17.5$17.5 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities.
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Nuclear Fuel Disposal Costs
In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is accounted as a component of nuclear fuel expense. Delays have occurred in the DOE’sThe DOE's Yucca Mountain Nuclear Waste Repository program for the acceptance and disposal of spent nuclear fuel at a permanent repository and the proposed fiscal year 2011 federal budget recommends termination of funding for completion of the government’s long-term storage facility.was terminated in 2011. Detroit Edison is a party in the litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Federal Nuclear Waste Policy Act of 1982. Detroit Edison currently employs a spent nuclear fuel storage strategy utilizing a fuel pool. In 2011, theThe Company expectscontinues to begin loading spent nuclear fuel into andevelop its on-site dry cask storage facility whichand has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.
Synthetic Fuel Guarantees
The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as
of December 31, 2007. The Company provided certain guarantees and indemnities in conjunction with the sales of
interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related
obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company
estimates that its maximum potential liability under these guarantees at December 31, 2011 is approximately $1.2 billion. Payment under these guarantees is considered remote.
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Reduced Emissions Fuel Guarantees
The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its reduced emissions fuel facilities. The guarantees cover potential commercial, environmental, and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2011 is approximately $15 million. Payment under these guarantees is considered remote.
Other Guarantees
In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others.
The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of December 31, 2010,2011, the Company had approximately $14$23 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.
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Labor Contracts
There are several bargaining units for the Company’s approximately 5,000 represented employees. In the 2010 third quarter, a new three-year agreement was ratified covering approximately 3,800 represented employees. The majority of the remaining represented employees are under contracts that expire in August 2012 and June 2011 and August 2012.October 2013.
Purchase Commitments
As of December 31, 2010,2011, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $6$5.3 billion from 20112012 through 2051 as detailed in the following table:
| (In millions) | ||||
| 2011 | $ | 2,175 | ||
| 2012 | 1,085 | |||
| 2013 | 585 | |||
| 2014 | 471 | |||
| 2015 | 273 | |||
| 2016 — 2051 | 1,332 | |||
| $ | 5,921 | |||
| (In millions) | |||
| 2012 | $ | 2,276 | |
| 2013 | 1,221 | ||
| 2014 | 732 | ||
| 2015 | 237 | ||
| 2016 | 109 | ||
| 2017 — 2051 | 740 | ||
| $ | 5,315 | ||
The Company also estimates that 20112012 capital expenditures will be approximately $1.4 billion.$1.9 billion. The Company has made certain commitments in connection with expected capital expenditures.
Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and other energy products from and to governmental entities and numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of its customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.
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Other Contingencies
The Company is involved in certain other legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. The Company cannot predict the final disposition of such proceedings. The Company regularly reviews legal matters and records provisions for claims that it can estimate and are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on the Company’s operations or financial statements in the periods they are resolved.
See Notes 54 and 1211 for a discussion of contingencies related to derivatives and regulatory matters.
NOTE 20 — RETIREMENT BENEFITS AND TRUSTEED ASSETS |
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Pension Plan Benefits
The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover substantially all employees. The plans provide traditional retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. In addition, certain represented and non-represented employees are covered under cash balance provisions that determine benefits on annual employer contributions and interest credits. The Company also maintains supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by DTE Energy’s other retirement plans.
The Company’s policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. The Company contributed $200$200 million to its pension plans in 2010, including2011. At the discretion of management, and depending upon financial market conditions, we anticipate making up to a $240 millioncontribution of DTE Energy stock of $100 million (consisting of approximately 2.2 million shares valued at an average price of $44.97 per share). In January 2011,to the Company contributed $200 million to its pension plans.
plans in 2012.
Net pension cost includes the following components:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Service cost | $ | 64 | $ | 52 | $ | 55 | ||||||
| Interest cost | 202 | 203 | 190 | |||||||||
| Expected return on plan assets | (258 | ) | (255 | ) | (259 | ) | ||||||
| Amortization of: | ||||||||||||
| Net actuarial loss | 100 | 52 | 32 | |||||||||
| Prior service cost | 4 | 6 | 6 | |||||||||
| Net pension cost | $ | 112 | $ | 58 | $ | 24 | ||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Service cost | $ | 69 | $ | 64 | $ | 52 | |||||
| Interest cost | 202 | 202 | 203 | ||||||||
| Expected return on plan assets | (246 | ) | (258 | ) | (255 | ) | |||||
| Amortization of: | |||||||||||
| Net actuarial loss | 142 | 100 | 52 | ||||||||
| Prior service cost | 3 | 4 | 6 | ||||||||
| Special termination benefits | 2 | — | — | ||||||||
| Net pension cost | $ | 172 | $ | 112 | $ | 58 | |||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets | ||||||||
| Net actuarial loss | $ | 166 | $ | 216 | ||||
| Amortization of net actuarial loss | (100 | ) | (52 | ) | ||||
| Amortization of prior service cost | (4 | ) | (6 | ) | ||||
| Total recognized in other comprehensive income and regulatory assets | $ | 62 | $ | 158 | ||||
| Total recognized in net periodic pension cost, Other comprehensive income and regulatory assets | $ | 174 | $ | 216 | ||||
| Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year | ||||||||
| Net actuarial loss | $ | 133 | $ | 100 | ||||
| Prior service cost | 3 | 4 | ||||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Other changes in plan assets and benefit obligations recognized in Regulatory assets and Other comprehensive income | |||||||
| Net actuarial loss | $ | 619 | $ | 166 | |||
| Amortization of net actuarial loss | (142 | ) | (100 | ) | |||
| Amortization of prior service cost | (3 | ) | (4 | ) | |||
| Total recognized Regulatory assets and Other comprehensive income | $ | 474 | $ | 62 | |||
| Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income | $ | 646 | $ | 174 | |||
| Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year | |||||||
| Net actuarial loss | $ | 171 | $ | 133 | |||
| Prior service cost | — | 3 | |||||
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the Consolidated Statements of Financial Position at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Accumulated benefit obligation, end of year | $ | 3,521 | $ | 3,193 | ||||
Change in projected benefit obligation | ||||||||
| Projected benefit obligation, beginning of year | $ | 3,436 | $ | 3,032 | ||||
| Consolidation of VIEs | 82 | — | ||||||
| Service cost | 64 | 52 | ||||||
| Interest cost | 202 | 203 | ||||||
| Actuarial loss | 216 | 351 | ||||||
| Benefits paid | (215 | ) | (202 | ) | ||||
| Projected benefit obligation, end of year | $ | 3,785 | $ | 3,436 | ||||
Change in plan assets | ||||||||
| Plan assets at fair value, beginning of year | $ | 2,549 | $ | 2,155 | ||||
| Consolidation of VIEs | 64 | — | ||||||
| Actual return on plan assets | 309 | 390 | ||||||
| Company contributions | 206 | 206 | ||||||
| Benefits paid | (215 | ) | (202 | ) | ||||
| Plan assets at fair value, end of year | $ | 2,913 | $ | 2,549 | ||||
| Funded status of the plans | $ | (872 | ) | $ | (887 | ) | ||
| Amount recorded as: | ||||||||
| Current liabilities | $ | (6 | ) | $ | (6 | ) | ||
| Noncurrent liabilities | (866 | ) | (881 | ) | ||||
| $ | (872 | ) | $ | (887 | ) | |||
Amounts recognized in Accumulated other comprehensive loss, pre-tax | ||||||||
| Net actuarial loss | $ | 195 | $ | 196 | ||||
| Prior service (credit) | (4 | ) | (5 | ) | ||||
| $ | 191 | $ | 191 | |||||
Amounts recognized in regulatory assets (see Note 12) | ||||||||
| Net actuarial loss | $ | 1,730 | $ | 1,653 | ||||
| Prior service cost | 12 | 17 | ||||||
| $ | 1,742 | $ | 1,670 | |||||
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| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Accumulated benefit obligation, end of year | $ | 3,881 | $ | 3,521 | |||
| Change in projected benefit obligation | |||||||
| Projected benefit obligation, beginning of year | $ | 3,785 | $ | 3,436 | |||
| Consolidation of VIEs | — | 82 | |||||
| Service cost | 69 | 64 | |||||
| Interest cost | 202 | 202 | |||||
| Actuarial loss | 355 | 216 | |||||
| Special termination benefits | 2 | — | |||||
| Benefits paid | (218 | ) | (215 | ) | |||
| Projected benefit obligation, end of year | $ | 4,195 | $ | 3,785 | |||
| Change in plan assets | |||||||
| Plan assets at fair value, beginning of year | $ | 2,913 | $ | 2,549 | |||
| Consolidation of VIEs | — | 64 | |||||
| Actual return on plan assets | (18 | ) | 309 | ||||
| Company contributions | 209 | 206 | |||||
| Benefits paid | (218 | ) | (215 | ) | |||
| Plan assets at fair value, end of year | $ | 2,886 | $ | 2,913 | |||
| Funded status of the plans | $ | (1,309 | ) | $ | (872 | ) | |
| Amount recorded as: | |||||||
| Current liabilities | $ | (11 | ) | $ | (6 | ) | |
| Noncurrent liabilities | (1,298 | ) | (866 | ) | |||
| $ | (1,309 | ) | $ | (872 | ) | ||
| Amounts recognized in Accumulated other comprehensive loss, pre-tax | |||||||
| Net actuarial loss | $ | 202 | $ | 195 | |||
| Prior service (credit) | (3 | ) | (4 | ) | |||
| $ | 199 | $ | 191 | ||||
| Amounts recognized in Regulatory assets (see Note 11) | |||||||
| Net actuarial loss | $ | 2,201 | $ | 1,730 | |||
| Prior service cost | 7 | 12 | |||||
| $ | 2,208 | $ | 1,742 | ||||
Assumptions used in determining the projected benefit obligation and net pension costs are listed below:
| 2010 | 2009 | 2008 | ||||||||||
Projected benefit obligation | ||||||||||||
| Discount rate | 5.50 | % | 5.90 | % | 6.90 | % | ||||||
| Rate of compensation increase | 4.00 | % | 4.00 | % | 4.00 | % | ||||||
Net pension costs | ||||||||||||
| Discount rate | 5.90 | % | 6.90 | % | 6.50 | % | ||||||
| Rate of compensation increase | 4.00 | % | 4.00 | % | 4.00 | % | ||||||
| Expected long-term rate of return on plan assets | 8.75 | % | 8.75 | % | 8.75 | % | ||||||
| 2011 | 2010 | 2009 | ||||||
| Projected benefit obligation | ||||||||
| Discount rate | 5.00 | % | 5.50 | % | 5.90 | % | ||
| Rate of compensation increase | 4.20 | % | 4.00 | % | 4.00 | % | ||
| Net pension costs | ||||||||
| Discount rate | 5.50 | % | 5.90 | % | 6.90 | % | ||
| Rate of compensation increase | 4.00 | % | 4.00 | % | 4.00 | % | ||
| Expected long-term rate of return on plan assets | 8.50 | % | 8.75 | % | 8.75 | % | ||
102
The Company employs a formal process in determining the long-term rate of return for various asset classes. Management reviews historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment and rebalancing. As a result of this process, the Company is lowering its long-term rate of return assumptions for its pension and OPEB plans to 8.50%8.25% for 2011.2012. The Company believes this rate is a reasonable assumption for the long-term rate of return on its plan assets for 20112012 given its investment strategy.
At December 31, 2010,2011, the benefits related to the Company’s qualified and nonqualified pension plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:
| (In millions) | ||||
| 2011 | $ | 217 | ||
| 2012 | 226 | |||
| 2013 | 231 | |||
| 2014 | 235 | |||
| 2015 | 244 | |||
| 2016 — 2020 | 1,343 | |||
| $ | 2,496 | |||
| (In millions) | |||
| 2012 | $ | 240 | |
| 2013 | 239 | ||
| 2014 | 244 | ||
| 2015 | 253 | ||
| 2016 | 260 | ||
| 2017-2021 | 1,439 | ||
| $ | 2,675 | ||
The Company employs a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return on plan assets consistent with prudent levels of risk, with consideration given to the liquidity needs of the plan. The intent of this strategy is to minimize plan expenses over the long-term. Risk tolerance is established through consideration of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S. andnon-U.S. stocks, growth and value investment styles, and large and small market capitalizations. Fixed income securities generally include corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other assets such as private equity and hedge funds are used to enhance long-term returns while improving portfolio diversification. Derivatives may be utilized in a risk controlled manner, to potentially increase the portfolio beyond the market value of invested assets andand/or reduce portfolio investment risk. Investment risk is measured and monitored
118
on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.
Target allocations for plan assets as of December 31, 20102011 are listed below:
| U.S. Large Cap Equity Securities | 22 | % | ||
| U.S. Small Cap and Mid Cap Equity Securities | 5 | |||
| Non U.S. Equity Securities | 20 | |||
| Fixed Income Securities | 25 | |||
| Hedge Funds and Similar Investments | 20 | |||
| Private Equity and Other | 8 | |||
| 100 | % | |||
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Fair Value Measurements at December 31, 2011(a)
| Level 1 | Level 2 | Level 3 | Balance at December 31, 2011 | ||||||||||||
| (In millions) | |||||||||||||||
| Asset Category: | |||||||||||||||
| Short-term investments (b) | $ | — | $ | 33 | $ | — | $ | 33 | |||||||
| Equity securities | |||||||||||||||
| U.S. Large Cap (c) | 640 | 40 | — | 680 | |||||||||||
| U.S. Small/Mid Cap (d) | 159 | 5 | — | 164 | |||||||||||
| Non U.S (e) | 392 | 114 | — | 506 | |||||||||||
| Fixed income securities (f) | 88 | 703 | — | 791 | |||||||||||
| Hedge Funds and Similar Investments (g) | 190 | 58 | 296 | 544 | |||||||||||
| Private Equity and Other (h) | — | — | 168 | 168 | |||||||||||
| Total | $ | 1,469 | $ | 953 | $ | 464 | $ | 2,886 | |||||||
Fair Value Measurements at December 31, 2010(a)
| Balance at | ||||||||||||||||
| December 31, | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2010 | |||||||||||||
| (In millions) | ||||||||||||||||
Asset Category: | ||||||||||||||||
| Short-term investments(b) | $ | — | $ | 34 | $ | — | $ | 34 | ||||||||
| Equity securities | ||||||||||||||||
| U.S. Large Cap(c) | 686 | 38 | — | 724 | ||||||||||||
| U.S. Small/Mid Cap(d) | 181 | 8 | — | 189 | ||||||||||||
| Non U.S(e) | 285 | 222 | — | 507 | ||||||||||||
| Fixed income securities(f) | 61 | 658 | — | 719 | ||||||||||||
| Other types of investments | ||||||||||||||||
| Hedge Funds and Similar Investments(g) | 189 | 73 | 304 | 566 | ||||||||||||
| Private Equity and Other(h) | — | — | 174 | 174 | ||||||||||||
| Total | $ | 1,402 | $ | 1,033 | $ | 478 | $ | 2,913 | ||||||||
119
| Level 1 | Level 2 | Level 3 | Balance at December 31, 2010 | ||||||||||||
| (In millions) | |||||||||||||||
| Asset Category: | |||||||||||||||
| Short-term investments (b) | $ | — | $ | 34 | $ | — | $ | 34 | |||||||
| Equity securities | |||||||||||||||
| U.S. Large Cap (c) | 686 | 38 | — | 724 | |||||||||||
| U.S. Small/Mid Cap (d) | 181 | 8 | — | 189 | |||||||||||
| Non U.S (e) | 285 | 222 | — | 507 | |||||||||||
| Fixed income securities (f) | 61 | 658 | — | 719 | |||||||||||
| Hedge Funds and Similar Investments (g) | 189 | 73 | 304 | 566 | |||||||||||
| Private Equity and Other (h) | — | — | 174 | 174 | |||||||||||
| Total | $ | 1,402 | $ | 1,033 | $ | 478 | $ | 2,913 | |||||||
| Balance at | ||||||||||||||||
| December 31, | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2009 | |||||||||||||
| (In millions) | ||||||||||||||||
Asset Category: | ||||||||||||||||
| Short-term investments(b) | $ | — | $ | 63 | $ | — | $ | 63 | ||||||||
| Equity securities | ||||||||||||||||
| U.S. Large Cap(c) | 659 | 30 | — | 689 | ||||||||||||
| U.S. Small/Mid Cap(d) | 153 | 3 | — | 156 | ||||||||||||
| Non U.S(e) | 231 | 120 | — | 351 | ||||||||||||
| Fixed income securities(f) | 47 | 599 | — | 646 | ||||||||||||
| Other types of investments | ||||||||||||||||
| Hedge Funds and Similar Investments(g) | — | — | 484 | 484 | ||||||||||||
| Private Equity and Other(h) | — | — | 160 | 160 | ||||||||||||
| Total | $ | 1,090 | $ | 815 | $ | 644 | $ | 2,549 | ||||||||
| (a) | See Note |
| (b) | This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services. |
| (c) | This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. |
| (d) | This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. |
| (e) | This category primarily consists of portfolios ofnon-U.S. developed and emerging market equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. |
| (f) | This category includes corporate bonds from diversified industries, U.S. Treasuries, and |
104
| (g) | This category |
| (h) | This category includes a diversified group of funds and strategies that primarily invests in private equity partnerships. This category also includes investments in timber and private mezzanine debt. Pricing for investments in this category is based on limited observable inputs as there is little, if any, publicly available pricing. Valuations for assets in this category may be based on discounted cash flow analyses, |
120
The pension trust holds debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on underlying securities, using quoted prices in actively traded markets. Non-exchange traded fixed income securities are valued by the trustee based upon quotations available from brokers or pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3):
| Hedge Funds | ||||||||||||
| and Similar | Private Equity | |||||||||||
| Investments | and Other | Total | ||||||||||
| (In millions) | ||||||||||||
| Beginning Balance at January 1, 2010 | $ | 484 | $ | 160 | $ | 644 | ||||||
| Total realized/unrealized gains (losses) | 51 | 23 | 74 | |||||||||
| Purchases, sales and settlements | (231 | ) | (9 | ) | (240 | ) | ||||||
| Ending Balance at December 31, 2010 | $ | 304 | $ | 174 | $ | 478 | ||||||
| The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period | $ | 29 | $ | 13 | $ | 42 | ||||||
Hedge Funds and Similar Investments | Private Equity and Other | Total | |||||||||
| (In millions) | |||||||||||
| Beginning Balance at January 1, 2011 | $ | 304 | $ | 174 | $ | 478 | |||||
| Total realized/unrealized gains (losses): | |||||||||||
| Realized gains (losses) | (4 | ) | 6 | 2 | |||||||
| Unrealized gains (losses) | 1 | (30 | ) | (29 | ) | ||||||
| Purchases, sales and settlements: | |||||||||||
| Purchases | 64 | 23 | 87 | ||||||||
| Sales | (69 | ) | (5 | ) | (74 | ) | |||||
| Ending Balance at December 31, 2011 | $ | 296 | $ | 168 | $ | 464 | |||||
| The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period | $ | 4 | $ | (28 | ) | $ | (24 | ) | |||
| Hedge Funds | ||||||||||||
| and Similar | Private Equity | |||||||||||
| Investments | and Other | Total | ||||||||||
| (In millions) | ||||||||||||
| Beginning Balance at January 1, 2009 | $ | 468 | $ | 159 | $ | 627 | ||||||
| Total realized/unrealized gains (losses) | 31 | (11 | ) | 20 | ||||||||
| Purchases, sales and settlements | (15 | ) | 12 | (3 | ) | |||||||
| Ending Balance at December 31, 2009 | $ | 484 | $ | 160 | $ | 644 | ||||||
| The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period | $ | 34 | $ | (10 | ) | $ | 24 | |||||
Hedge Funds and Similar Investments | Private Equity and Other | Total | |||||||||
| (In millions) | |||||||||||
| Beginning Balance at January 1, 2010 | $ | 484 | $ | 160 | $ | 644 | |||||
| Total realized/unrealized gains (losses) | 51 | 23 | 74 | ||||||||
| Purchases, sales and settlements | (231 | ) | (9 | ) | (240 | ) | |||||
| Ending Balance at December 31, 2010 | $ | 304 | $ | 174 | $ | 478 | |||||
| The amount of total gains (losses) for the period attributable to the change in unrealized gains or losses related to assets still held at the end of the period | $ | 29 | $ | 13 | $ | 42 | |||||
105
There were no transfers between Level 3 and Level 2 and there were no significant transfers between Level 2 and Level 1 in the years ended December 31, 2011 and 2010.
The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches employee contributions up to certain predefined limits based upon eligible compensation, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $34$35 million $33, $34 million, and $33$33 million in each of the years 2011, 2010, and 2009, and 2008, respectively.
Other Postretirement Benefits
The Company provides certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. The Company’s policy is to fund certain trusts to meet its postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) and 401(h) trusts exist for
121
represented and non-represented employees. The Company contributed $160$111 million to its postretirement medical and life insurance benefit plans during 2010, including a transfer of $25 million from the MichCon Grantor Trust.2011.
In January 2011,2012, the Company contributed $81$140 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $90$120 million contribution to its VEBA trusts through the remainder of 2011.
in 2012.
Net postretirement cost includes the following components:
| 2010 | 2009 | 2008 | ||||||||||
| (In millions) | ||||||||||||
| Service cost | $ | 61 | $ | 59 | $ | 62 | ||||||
| Interest cost | 125 | 133 | 121 | |||||||||
| Expected return on plan assets | (74 | ) | (55 | ) | (75 | ) | ||||||
| Amortization of: | ||||||||||||
| Net loss | 54 | 72 | 38 | |||||||||
| Prior service (credit) | (4 | ) | (6 | ) | (6 | ) | ||||||
| Net transition obligation | 2 | 2 | 2 | |||||||||
| Net postretirement cost | $ | 164 | $ | 205 | $ | 142 | ||||||
| 2011 | 2010 | 2009 | |||||||||
| (In millions) | |||||||||||
| Service cost | $ | 64 | $ | 61 | $ | 59 | |||||
| Interest cost | 121 | 125 | 133 | ||||||||
| Expected return on plan assets | (94 | ) | (74 | ) | (55 | ) | |||||
| Amortization of: | |||||||||||
| Net loss | 55 | 54 | 72 | ||||||||
| Prior service (credit) | (26 | ) | (4 | ) | (6 | ) | |||||
| Net transition obligation | 2 | 2 | 2 | ||||||||
| Net postretirement cost | $ | 122 | $ | 164 | $ | 205 | |||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Other changes in plan assets and APBO recognized in other comprehensive income and regulatory assets | ||||||||
| Net actuarial loss (gain) | $ | 93 | $ | (59 | ) | |||
| Amortization of net actuarial loss | (54 | ) | (72 | ) | ||||
| Prior service cost (credit) | (79 | ) | — | |||||
| Amortization of prior service credit | 4 | 6 | ||||||
| Amortization of transition (asset) | (2 | ) | (2 | ) | ||||
| Total recognized in other comprehensive income and regulatory assets | $ | (38 | ) | $ | (127 | ) | ||
| Total recognized in net periodic pension cost, other comprehensive income and regulatory assets | $ | 126 | $ | 78 | ||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Other changes in plan assets and APBO recognized in Regulatory assets and Other comprehensive income | |||||||
| Net actuarial loss | $ | 195 | $ | 93 | |||
| Amortization of net actuarial loss | (55 | ) | (54 | ) | |||
| Prior service credit | (4 | ) | (79 | ) | |||
| Amortization of prior service credit | 26 | 4 | |||||
| Amortization of transition asset | (2 | ) | (2 | ) | |||
| Total recognized in Regulatory assets and Other comprehensive income | $ | 160 | $ | (38 | ) | ||
| Total recognized in net periodic pension cost, Regulatory assets and Other comprehensive income | $ | 282 | $ | 126 | |||
| Estimated amounts to be amortized from Regulatory assets and Accumulated other comprehensive income into net periodic benefit cost during next fiscal year | |||||||
| Net actuarial loss | $ | 78 | $ | 59 | |||
| Prior service credit | $ | (27 | ) | $ | (26 | ) | |
| Net transition obligation | $ | 2 | $ | 2 | |||
| 2010 | 2009 | |||||||
Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year | ||||||||
| Net actuarial loss | $ | 59 | $ | 53 | ||||
| Prior service (credit) | $ | (26 | ) | $ | (3 | ) | ||
| Net transition obligation | $ | 2 | $ | 2 | ||||
122
106
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statements of Financial Position at December 31:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
Change in accumulated postretirement benefit obligation | ||||||||
| Accumulated postretirement benefit obligation, beginning of year | $ | 2,151 | $ | 2,032 | ||||
| Consolidation of VIEs | 21 | — | ||||||
| Service cost | 61 | 59 | ||||||
| Interest cost | 125 | 133 | ||||||
| Plan amendments | (79 | ) | — | |||||
| Actuarial loss | 127 | 22 | ||||||
| Medicare Part D subsidy | 7 | 6 | ||||||
| Benefits paid | (108 | ) | (101 | ) | ||||
| Accumulated postretirement benefit obligation, end of year | $ | 2,305 | $ | 2,151 | ||||
Change in plan assets | ||||||||
| Plan assets at fair value, beginning of year | $ | 864 | $ | 598 | ||||
| Actual return on plan assets | 108 | 135 | ||||||
| Company contributions | 160 | 205 | ||||||
| Benefits paid | (103 | ) | (74 | ) | ||||
| Plan assets at fair value, end of year | $ | 1,029 | $ | 864 | ||||
| Funded status, end of year | $ | (1,276 | ) | $ | (1,287 | ) | ||
Amount recorded as: | ||||||||
| Current liabilities | $ | (1 | ) | $ | — | |||
| Noncurrent liabilities | $ | (1,275 | ) | $ | (1,287 | ) | ||
| $ | (1,276 | ) | $ | (1,287 | ) | |||
Amounts recognized in Accumulated other comprehensive loss, pre-tax | ||||||||
| Net actuarial loss | $ | 46 | $ | 51 | ||||
| Prior service (credit) | (28 | ) | (27 | ) | ||||
| Net transition (asset) | (2 | ) | (12 | ) | ||||
| $ | 16 | $ | 12 | |||||
Amounts recognized in regulatory assets (See Note 12) | ||||||||
| Net actuarial loss | $ | 692 | $ | 646 | ||||
| Prior service cost | (74 | ) | 1 | |||||
| Net transition obligation | 6 | 18 | ||||||
| $ | 624 | $ | 665 | |||||
| 2011 | 2010 | ||||||
| (In millions) | |||||||
| Change in accumulated postretirement benefit obligation | |||||||
| Accumulated postretirement benefit obligation, beginning of year | $ | 2,305 | $ | 2,151 | |||
| Consolidation of VIEs | — | 21 | |||||
| Service cost | 64 | 61 | |||||
| Interest cost | 121 | 125 | |||||
| Plan amendments | (4 | ) | (79 | ) | |||
| Actuarial loss | 80 | 127 | |||||
| Medicare Part D subsidy | 6 | 7 | |||||
| Benefits paid | (102 | ) | (108 | ) | |||
| Accumulated postretirement benefit obligation, end of year | $ | 2,470 | $ | 2,305 | |||
| Change in plan assets | |||||||
| Plan assets at fair value, beginning of year | $ | 1,029 | $ | 864 | |||
| Actual return on plan assets | (22 | ) | 108 | ||||
| Company contributions | 111 | 160 | |||||
| Benefits paid | (133 | ) | (103 | ) | |||
| Plan assets at fair value, end of year | $ | 985 | $ | 1,029 | |||
| Funded status, end of year | $ | (1,485 | ) | $ | (1,276 | ) | |
| Amount recorded as: | |||||||
| Current liabilities | $ | (1 | ) | $ | (1 | ) | |
| Noncurrent liabilities | $ | (1,484 | ) | $ | (1,275 | ) | |
| $ | (1,485 | ) | $ | (1,276 | ) | ||
| Amounts recognized in Accumulated other comprehensive loss, pre-tax | |||||||
| Net actuarial loss | $ | 47 | $ | 46 | |||
| Prior service credit | (20 | ) | (28 | ) | |||
| Net transition asset | (1 | ) | (2 | ) | |||
| $ | 26 | $ | 16 | ||||
| Amounts recognized in Regulatory assets (See Note 11) | |||||||
| Net actuarial loss | $ | 835 | $ | 692 | |||
| Prior service cost | (60 | ) | (74 | ) | |||
| Net transition obligation | 3 | 6 | |||||
| $ | 778 | $ | 624 | ||||
107
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:
| 2010 | 2009 | 2008 | ||||||||||
Projected benefit obligation | ||||||||||||
| Discount rate | 5.50 | % | 5.90 | % | 6.90 | % | ||||||
Net benefit costs | ||||||||||||
| Discount rate | 5.90 | % | 6.90 | % | 6.50 | % | ||||||
| Expected long-term rate of return on plan assets | 8.75 | % | 8.75 | % | 8.75 | % | ||||||
| Health care trend rate pre-65 | 7.00 | % | 7.00 | % | 7.00 | % | ||||||
| Health care trend rate post-65 | 7.00 | % | 7.00 | % | 6.00 | % | ||||||
| Ultimate health care trend rate | 5.00 | % | 5.00 | % | 5.00 | % | ||||||
| Year in which ultimate reached | 2016 | 2016 | 2011 | |||||||||
| 2011 | 2010 | 2009 | ||||||
| Projected benefit obligation | ||||||||
| Discount rate | 5.00 | % | 5.50 | % | 5.90 | % | ||
| Net benefit costs | ||||||||
| Discount rate | 5.50 | % | 5.90 | % | 6.90 | % | ||
| Expected long-term rate of return on plan assets | 8.75 | % | 8.75 | % | 8.75 | % | ||
| Health care trend rate pre- and post- 65 | 7.00 | % | 7.00 | % | 7.00 | % | ||
| Ultimate health care trend rate | 5.00 | % | 5.00 | % | 5.00 | % | ||
| Year in which ultimate reached | 2019 | 2016 | 2016 | |||||
A one percentage point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $32$35 million and increased the accumulated benefit obligation by $300$306 million at December 31, 2010.2011. A one percentage point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $28$23 million and would have decreased the accumulated benefit obligation by $287$297 million at December 31, 2010.2011.
At December 31, 2010,2011, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:
| (In millions) | ||||
| 2011 | $ | 110 | ||
| 2012 | 114 | |||
| 2013 | 137 | |||
| 2014 | 144 | |||
| 2015 | 151 | |||
| 2016 — 2020 | 866 | |||
| $ | 1,522 | |||
| (In millions) | |||
| 2012 | $ | 109 | |
| 2013 | 116 | ||
| 2014 | 124 | ||
| 2015 | 132 | ||
| 2016 | 142 | ||
| 2017 — 2021 | 839 | ||
| $ | 1,462 | ||
The process used in determining the long-term rate of return for assets and the investment approach for the Company’s other postretirement benefits plans is similar to those previously described for its pension plans.
Target allocations for plan assets as of December 31, 20102011 are listed below:
| U.S. Large Cap Equity Securities | % | |||
| Non U.S. Equity Securities | 20 | |||
| Fixed Income Securities | 25 | |||
| Hedge Funds and Similar Investments | 20 | |||
| Private Equity and Other | 13 | |||
| 100 | % | |||
124
108
Fair Value Measurements at December 31, 2011(a)
| Level 1 | Level 2 | Level 3 | Balance at December 31, 2011 | ||||||||||||
| (In millions) | |||||||||||||||
| Asset Category: | |||||||||||||||
| Short-term investments (b) | $ | — | $ | 13 | $ | — | $ | 13 | |||||||
| Equity securities: | |||||||||||||||
| U.S. Large Cap (c) | 175 | 15 | — | 190 | |||||||||||
| U.S. Small/Mid Cap (d) | 70 | 6 | — | 76 | |||||||||||
| Non U.S (e) | 176 | 14 | — | 190 | |||||||||||
| Fixed income securities (f) | 24 | 236 | — | 260 | |||||||||||
| Hedge Funds and Similar Investments (g) | 80 | 21 | 95 | 196 | |||||||||||
| Private Equity and Other (h) | — | — | 60 | 60 | |||||||||||
| Total | $ | 525 | $ | 305 | $ | 155 | $ | 985 | |||||||
Fair Value Measurements at December 31, 2010(a)
| Balance at | ||||||||||||||||
| December 31, | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2010 | |||||||||||||
| (In millions) | ||||||||||||||||
Asset Category: | ||||||||||||||||
| Short-term investments(b) | $ | — | $ | 8 | $ | — | $ | 8 | ||||||||
| Equity securities | ||||||||||||||||
| U.S. Large Cap(c) | 126 | 62 | — | 188 | ||||||||||||
| U.S. Small/Mid Cap(d) | 60 | 58 | — | 118 | ||||||||||||
| Non U.S(e) | 79 | 122 | — | 201 | ||||||||||||
| Fixed income securities(f) | 4 | 252 | — | 256 | ||||||||||||
| Other types of investments | ||||||||||||||||
| Hedge Funds and Similar Investments(g) | 76 | 48 | 79 | 203 | ||||||||||||
| Private Equity and Other(h) | — | — | 55 | 55 | ||||||||||||
| Total | $ | 345 | $ | 550 | $ | 134 | $ | 1,029 | ||||||||
| Level 1 | Level 2 | Level 3 | Balance at December 31, 2010 | ||||||||||||
| (In millions) | |||||||||||||||
| Asset Category: | |||||||||||||||
| Short-term investments (b) | $ | — | $ | 8 | $ | — | $ | 8 | |||||||
| Equity securities | |||||||||||||||
| U.S. Large Cap (c) | 126 | 62 | — | 188 | |||||||||||
| U.S. Small/Mid Cap (d) | 60 | 58 | — | 118 | |||||||||||
| Non U.S (e) | 79 | 122 | — | 201 | |||||||||||
| Fixed income securities (f) | 4 | 252 | — | 256 | |||||||||||
| Hedge Funds and Similar Investments (g) | 76 | 48 | 79 | 203 | |||||||||||
| Private Equity and Other (h) | — | — | 55 | 55 | |||||||||||
| Total | $ | 345 | $ | 550 | $ | 134 | $ | 1,029 | |||||||
| Balance at | ||||||||||||||||
| December 31, | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | 2009 | |||||||||||||
| (In millions) | ||||||||||||||||
Asset Category: | ||||||||||||||||
| Short-term investments(b) | $ | — | $ | 18 | $ | — | $ | 18 | ||||||||
| Equity securities | ||||||||||||||||
| U.S. Large Cap(c) | 148 | 80 | — | 228 | ||||||||||||
| U.S. Small/Mid Cap(d) | 46 | 50 | — | 96 | ||||||||||||
| Non U.S(e) | 73 | 69 | — | 142 | ||||||||||||
| Fixed income securities(f) | 8 | 234 | — | 242 | ||||||||||||
| Other types of investments | ||||||||||||||||
| Hedge Funds and Similar Investments(g) | — | — | 92 | 92 | ||||||||||||
| Private Equity and Other(h) | — | — | 46 | 46 | ||||||||||||
| Total | $ | 275 | $ | 451 | $ | 138 | $ | 864 | ||||||||
| (a) | See Note |
| (b) | This category predominantly represents certain short-term fixed income securities and money market investments that are managed in separate accounts or commingled funds. Pricing for investments in this category are obtained from quoted prices in actively traded markets or valuations from brokers or pricing services. |
| (c) | This category comprises both actively and not actively managed portfolios that track the S&P 500 low cost equity index funds. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. |
| (d) | This category represents portfolios of small and medium capitalization domestic equities. Investments in this category are exchange-traded securities whereby unadjusted quote prices can be obtained. Exchange-traded securities held in a commingled fund are classified as Level 2 assets. |
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