DTEEnergy Company
Annual Report onForm 10-K
Year Ended December 31,20072008
TABLE OF CONTENTS
Annual Report onForm 10-K
Year Ended December 31,
TABLE OF CONTENTS
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DEFINITIONS
| Company | DTE Energy Company and any subsidiary companies | |
| CTA | Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process | |
| Customer Choice | Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas. | |
| Detroit Edison | The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies | |
| DTE Energy | DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries | |
| EPA | United States Environmental Protection Agency | |
| FASB | Financial Accounting Standards Board | |
| FERC | Federal Energy Regulatory Commission | |
| GCR | A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers. | |
| MDEQ | Michigan Department of Environmental Quality | |
| MichCon | Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies | |
| MISO | Midwest Independent System Operator, a Regional Transmission Organization | |
| MPSC | Michigan Public Service Commission | |
| Non-utility | An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC or the FERC. | |
| NRC | Nuclear Regulatory Commission | |
| Production tax credits | Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service. | |
| Proved | Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. | |
| PSCR | A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses. | |
| Securitization | Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly-owned special purpose entity, the Detroit Edison Securitization Funding LLC. | |
| SFAS | Statement of Financial Accounting Standards |
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| Subsidiaries | The direct and indirect subsidiaries of DTE Energy Company |
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| Synfuels | The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production through December 31, 2007 generated production tax credits. | |
| Unconventional Gas | Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations. |
Units of Measurement
| Bcf | Billion cubic feet of gas | |
| Bcfe | Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil. | |
| GWh | Gigawatthour of electricity | |
| kWh | Kilowatthour of electricity | |
| Mcf | Thousand cubic feet of gas | |
| MMcf | Million cubic feet of gas | |
| MW | Megawatt of electricity | |
| MWh | Megawatthour of electricity |
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Forward-Looking Statements
Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those presently contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:
| • | access to capital markets and capital market conditions and the | ||
| • | |||
| • | potential for continued loss on cash equivalents and investments, including nuclear decommissioning and benefit plan assets; | ||
| • | the length and severity of ongoing economic decline; | ||
| • | the timing and extent of changes in interest rates; | ||
| • | the level of borrowings; | ||
| • | the availability, cost, coverage and terms of insurance and stability of insurance providers; | ||
| • | changes in the economic and financial viability of our customers, suppliers, and trading counterparties, and the continued ability of such parties to perform their obligations to the Company; | ||
| • | the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers; | ||
| • | economic climate and population growth or decline in the geographic areas where we do business; | ||
| • | environmental issues, laws, regulations, and the | ||
| • | nuclear regulations and operations associated with nuclear facilities; | ||
| • | impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs; | ||
| • | employee relations and the impact of collective bargaining agreements; | ||
| • | unplanned outages; | ||
| • | |||
| changes in the cost and availability of coal and other raw materials, purchased power and natural gas; | |||
| • | the effects of competition; | ||
| • | the uncertainties of successful exploration of gas shale resources and inability to estimate gas reserves with certainty; | ||
| • | impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures; | ||
| • | contributions to earnings by non-utility subsidiaries; | ||
| • | changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits; | ||
| • | the ability to recover costs through rate increases; | ||
| • |
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| the cost of protecting assets against, or damage due to, terrorism; | |||
| • | changes in and application of accounting standards and financial reporting regulations; |
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| • | changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues; | ||
| • | amounts of uncollectible accounts receivable; | ||
| • |
New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.
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Part I
Items 1. and 2. Business and Properties
General
In 1995, DTE Energy incorporated in the State of Michigan. Our utility operations consist primarily of Detroit Edison and MichCon. We also have four non-utility segments that are engaged in a variety of energy relatedenergy-related businesses.
Detroit Edison is a Michigan corporation organized in 1903 and is a public utility subject to regulation by the MPSC and the FERC. Detroit Edison is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.
MichCon is a Michigan corporation organized in 1898 and is a public utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.31.2 million customers throughout Michigan.
Our four non-utility segments are involved in 1) coal transportation and marketing, gas pipelines processing and storage; 2) unconventional gas projectexploration, 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 Relations page of our website:www.dteenergy.com, as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission (SEC). Our previously filed reports and statements are also available at the SEC’s website:www.sec.gov.
The Company’s Code of Ethics and Standards of Behavior, Board of Directors Mission and Guidelines, Board Committee Charters, and Categorical Standards of Director Independence are also posted on its website. The information on the Company’s website is not part of this or any other report that the Company files with, or furnishes to, the SEC.
Additionally, the public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC 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 at www.sec.gov.www.sec.gov.
References in this Report to “we,” “us,” “our,” “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
Corporate Structure
Based on the following structure, we set strategic goals, allocate resources, and evaluate performance. See Note 1920 of the Notes to Consolidated Financial Statements in Item 8 of this Report for financial information by segment for the last three years.
Electric Utility
| • | Consists of Detroit Edison, our electric utility whose operations include the power generation and electric distribution facilities that service approximately 2.2 million residential, commercial, industrial and wholesale customers throughout southeastern Michigan. |
Gas Utility
| • | Consists of the gas distribution services provided by MichCon, a gas utility that purchases, stores, transports and distributes natural gas throughout Michigan to approximately 1.2 million residential, |
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| commercial and industrial customers, and Citizens Gas Fuel Company (Citizens), a gas utility that distributes natural gas in Adrian, Michigan to approximately 17,000 customers. |
| • | |||
| • | Unconventional Gas Production,primarily consisting of unconventional gas | ||
| • | Power and Industrial Projects, primarily consisting ofon-site energy services, steel-related projects, | ||
| • | Energy Trading,primarily consisting of energy marketing and trading operations. |
Corporate & Other,, primarily consisting of corporate staff functions that are fully allocated to theincludes various segments based on services utilized. Additionally, Corporate & Otherholding company activities, holds certain non-utility debt and energy-related investments.
Refer to our Management’s Discussion and Analysis in Item 7 of this Report for an in-depth analysis of each segment’s financial results. A description of each business unit follows.
ELECTRIC UTILITY
Description
Our Electric Utility segment consists of Detroit Edison. Our generating plants are regulated by numerous federal and state governmental agencies, including, but not limited to, the MPSC, the FERC, the NRC, the EPA and the MDEQ. Electricity is generated from our several fossil plants, a hydroelectric pumped storage plant and a nuclear plant, and is purchased from electricity generators, suppliers and wholesalers.
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The electricity we produce and purchase is sold to four major classes of customers: residential, commercial, industrial, and wholesale, principally throughout southeastern Michigan.
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Revenue by Service
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Residential | $ | 1,739 | $ | 1,671 | $ | 1,517 | ||||||
| Commercial | 1,723 | 1,603 | 1,331 | |||||||||
| Industrial | 854 | 835 | 697 | |||||||||
| Wholesale | 125 | 109 | 73 | |||||||||
| Other | 259 | 350 | 464 | |||||||||
| Subtotal | 4,700 | 4,568 | 4,082 | |||||||||
| Interconnection sales (1) | 200 | 169 | 380 | |||||||||
| Total Revenue | $ | 4,900 | $ | 4,737 | $ | 4,462 | ||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Residential | $ | 1,726 | $ | 1,739 | $ | 1,671 | ||||||
| Commercial | 1,753 | 1,723 | 1,603 | |||||||||
| Industrial | 894 | 854 | 835 | |||||||||
| Wholesale | 119 | 125 | 109 | |||||||||
| Other | 170 | 259 | 350 | |||||||||
| Subtotal | 4,662 | 4,700 | 4,568 | |||||||||
| Interconnection sales(1) | 212 | 200 | 169 | |||||||||
| Total Revenue | $ | 4,874 | $ | 4,900 | $ | 4,737 | ||||||
| (1) | Represents power that is not distributed by Detroit Edison. |
Weather, economic factors, competition and electricity prices affect sales levels to customers. Our peak load and highest total system sales generally occur during the third quarter of the year, driven by air conditioning and other cooling-related demands.
We occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. Restoration and other costs associated with storm-related power outages can negatively impact earnings.
In the December 23, 2008 MPSC rate order for Detroit Edison, a tracking mechanism was approved that provides for an annual reconciliation for restoration costs (storm and non-storm) using a base expense level of $110 million per year. Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on Detroit Edison.
Fuel Supply and Purchased Power
Our power is generated from a variety of fuels and is supplemented with purchased power. We expect to have an adequate supply of fuel and purchased power to meet our obligation to serve customers. Our generating capability is heavily dependent upon the availability of coal. Coal is purchased from various sources in different geographic areas under agreements that vary in both pricing and terms. We expect to obtain the majority of our coal requirements through long-term contracts, with the balance to be obtained through short-term agreements and spot purchases. We have foureight long-term and eighttwo short-term contracts for a total purchase of approximately 25.726 million tons of low-sulfur western coal to be delivered from 2008 throughin 2009 and 2010. We also have 12eight contracts for the purchase of approximately 10.36 million tons of Appalachian coal to be delivered from 20082009 through 2010.2011. All of these contracts have fixed prices. We have approximately 90%84% of our 20082009 expected coal requirements under contract. Given the geographic diversity of supply, we believe we can meet our expected generation requirements. We lease a fleet of rail cars and have long-term transportation contracts with companies to provide rail and vessel services for delivery of purchased coal to our generating facilities.
Detroit Edison participates in the energy market through MISO. We offer our generation in the market on a day-ahead and real-time basis and bid for power in the market to serve our load. We are a net purchaser of power that supplements our generation capability to meet customer demand during peak cycles.
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Properties
Detroit Edison owns generating plants and facilities that are located in the State of Michigan. Substantially all of our property is subject to the lien of a mortgage.
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Generating plants owned and in service as of December 31, 20072008 are as follows:
| Location by | Summer Net | Location by | Summer Net | |||||||||||||||||||||||||
| Michigan | Rated Capability (1) (2) | Michigan | Rated Capability(1)(2) | |||||||||||||||||||||||||
| Plant Name | County | (MW) | (%) | Year in Service | County | (MW) | (%) | Year in Service | ||||||||||||||||||||
| Fossil-fueled Steam-Electric | ||||||||||||||||||||||||||||
| Belle River (3) | St. Clair | 1,026 | 9.3 | 1984 and 1985 | ||||||||||||||||||||||||
| Belle River(3) | St. Clair | 1,026 | 9.2 | 1984 and 1985 | ||||||||||||||||||||||||
| Conners Creek | Wayne | 230 | 2.1 | 1951 | Wayne | 230 | 2.1 | 1951 | ||||||||||||||||||||
| Greenwood | St. Clair | 785 | 7.1 | 1979 | St. Clair | 785 | 7.1 | 1979 | ||||||||||||||||||||
| Harbor Beach | Huron | 103 | 0.9 | 1968 | Huron | 103 | 0.9 | 1968 | ||||||||||||||||||||
| Monroe (4) | Monroe | 3,115 | 28.3 | 1971, 1973 and 1974 | ||||||||||||||||||||||||
| Marysville | St. Clair | 84 | 0.8 | 1943 and 1947 | ||||||||||||||||||||||||
| Monroe(4) | Monroe | 3,115 | 28.0 | 1971, 1973 and 1974 | ||||||||||||||||||||||||
| River Rouge | Wayne | 523 | 4.8 | 1957 and 1958 | Wayne | 523 | 4.7 | 1957 and 1958 | ||||||||||||||||||||
| St. Clair | St. Clair | 1,368 | 12.4 | 1953, 1954, 1959, 1961 and 1969 | St. Clair | 1,368 | 12.3 | 1953, 1954, 1959, 1961 and 1969 | ||||||||||||||||||||
| Trenton Channel | Wayne | 730 | 6.6 | 1949 and 1968 | Wayne | 730 | 6.6 | 1949 and 1968 | ||||||||||||||||||||
| 7,880 | 71.5 | 7,964 | 71.7 | |||||||||||||||||||||||||
| Oil or Gas-fueled Peaking Units | Various | 1,101 | 10.0 | 1966-1971, 1981 and 1999 | Various | 1,101 | 9.9 | 1966-1971, 1981 and 1999 | ||||||||||||||||||||
| Nuclear-fueled Steam-Electric Fermi 2 (5) | Monroe | 1,122 | 10.2 | 1988 | ||||||||||||||||||||||||
| Hydroelectric Pumped Storage Ludington (6) | Mason | 917 | 8.3 | 1973 | ||||||||||||||||||||||||
| Nuclear-fueled Steam-Electric Fermi 2(5) | Monroe | 1,122 | 10.1 | 1988 | ||||||||||||||||||||||||
| Hydroelectric Pumped Storage Ludington(6) | Mason | 917 | 8.3 | 1973 | ||||||||||||||||||||||||
| 11,020 | 100.0 | 11,104 | 100.0 | |||||||||||||||||||||||||
| (1) | Summer net rated capabilities of generating plants in service are based on periodic load tests and are changed depending on operating experience, the physical condition of units, environmental control limitations and customer requirements for steam, which otherwise would be used for electric generation. | |
| (2) | Excludes one oil-fueled unit, St. Clair Unit No. 5 (250 MW) | |
| (3) | The Belle River capability represents Detroit Edison’s entitlement to 81.39% of the capacity and energy of the plant. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report. | |
| (4) | The Monroe Power Plant provided | |
| (5) | Fermi 2 has a design electrical rating (net) of 1,150 MW. | |
| (6) | Represents Detroit Edison’s 49% interest in Ludington with a total capability of 1,872 MW. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Report. |
Detroit Edison owns and operates 678 distribution substations with a capacity of approximately 33,376,000 33,436,000kilovolt-amperes (kVA) and approximately 427,100419,600 line transformers with a capacity of approximately 26,280,00021,634,000 kVA.
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Circuit miles of distribution lines owned and in service as of December 31, 2007 are as follows:2008:
Electric Distribution
| �� | ||||||||||||||||
| Circuit Miles | Circuit Miles | |||||||||||||||
| Operating Voltage-Kilovolts (kV) | Overhead | Underground | Overhead | Underground | ||||||||||||
| 4.8 kV to 13.2 kV | 28,202 | 13,985 | 28,114 | 13,875 | ||||||||||||
| 24 kV | 99 | 690 | 102 | 690 | ||||||||||||
| 40 kV | 2,324 | 335 | 2,324 | 335 | ||||||||||||
| 120 kV | 72 | 13 | 72 | 13 | ||||||||||||
| 30,697 | 15,023 | 30,612 | 14,913 | |||||||||||||
There are numerous interconnections that allow the interchange of electricity between Detroit Edison and electricity providers external to our service area. These interconnections are generally owned and operated by ITC Transmission and connect to neighboring energy companies.
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Regulation
Detroit Edison’s business is subject to the regulatory jurisdiction of various agencies, including, but not limited to, the MPSC, the FERC and the NRC. The MPSC issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. The FERC regulates Detroit Edison with respect to financing authorization and wholesale electric activities. The NRC has regulatory jurisdiction over all phases of the operation, construction, licensing and decommissioning of Detroit Edison’s nuclear plant operations. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Energy Assistance Programs
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to Detroit Edison’s ability to control its uncollectible accounts receivable and collections expenses. Detroit Edison’s uncollectible accounts receivable expense is directly affected by the level of government-funded assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.
Strategy and Competition
We strive to be the preferred supplier of electrical generation in southeast Michigan. We can accomplish this goal by working with our customers, communities and regulatory agencies to be a reliable, low-cost supplier of electricity. To ensure generation reliability, we continue to invest in our generating plants, which will improve both plant availability and operating efficiencies. We also are making capital investments in areas that have a positive impact on reliability and environmental compliance with the goal of high customer satisfaction.
Our distribution operations focus on improving reliability, restoration time and the quality of customer service. We seek to lower our operating costs by improving operating efficiencies. Revenues from year to year will vary due to weather conditions, economic factors, regulatory events and other risk factors as discussed in the “Risk Factors” in Item 1A. of this Report.
The electric Customer Choice program in Michigan allows all of our electric customers to purchase their electricity from alternative electric suppliers of generation services. Customers choosing to purchase power from alternative electric suppliers represented approximately 4%3% of retail sales in 2008, 4% in 2007 and 6% in 2006 and 12% of
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such sales in 2005.2006. Customers participating in the electric Customer Choice program consist primarily of industrial and commercial customers whose MPSC-authorized full service rates exceed their cost of service. Customers who elect to purchase their electricity from alternative electric suppliersMPSC rate orders and recent energy legislation enacted by participating in the State of Michigan are phasing out the pricing disparity over five years and have placed a 10 percent cap on the total potential Customer Choice related migration, mitigating some of the unfavorable effects of electric Customer Choice program have an unfavorable effect on our financial performance. Recent higher wholesale electric prices have also resulted in many former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. When market conditions are favorable, we sell power into the wholesale market, in order to lower costs to full-service customers.
Competition in the regulated electric distribution business is primarily from 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. In 2008, the Michigan legislature passed a comprehensive reform package that requires Michigan utilities to serve ten percent of their retail sales from renewable energy sources by 2015. In December 2008, Detroit Edison issued a request for proposal to purchase Michigan-based renewable energy credits.
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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
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Gas sales | $ | 1,536 | $ | 1,541 | $ | 1,860 | $ | 1,824 | $ | 1,536 | $ | 1,541 | ||||||||||||
| End user transportation | 140 | 135 | 134 | 143 | 140 | 135 | ||||||||||||||||||
| Intermediate transportation | 59 | 69 | 58 | 73 | 59 | 69 | ||||||||||||||||||
| Storage and other | 140 | 104 | 86 | 112 | 140 | 104 | ||||||||||||||||||
| Total Revenue | $ | 1,875 | $ | 1,849 | $ | 2,138 | $ | 2,152 | $ | 1,875 | $ | 1,849 | ||||||||||||
| • | Gas sales —Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers. | |
| • | End user transportation —Gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our Customer Choice program. End user transportation customers purchase natural gas directly from producers or brokers and utilize our pipeline network to transport the gas to their facilities or homes. | |
| • | Intermediate transportation —Gas delivery service provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers utilize our gathering and high-pressure transmission system to transport the gas to storage fields, processing plants, pipeline interconnections or other locations. | |
| • | Storage and other —Includes revenues from gas storage, |
Our gas sales, end user transportation and intermediate transportation volumes, revenues and net income are impacted by weather. Given the seasonal nature of our business, revenues and net income are concentrated in the first and fourth quarters of the calendar year. By the end of the first quarter, the heating season is
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largely over, and we typically realize substantially reduced revenues and earnings in the second quarter and losses in the third quarter.
Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers would not have a material adverse effect on our Gas Utility segment.
Natural Gas Supply
Our gas distribution system has a planned maximum daily send-out capacity of 2.8 Bcf, with approximately 72%68% of the volume coming from underground storage for 2007.2008. Peak-use requirements are met through utilization of our storage facilities, pipeline transportation capacity, and purchased gas supplies. Because of our geographic diversity of supply and our pipeline transportation and storage capacity, we are able to reliably meet our supply requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.
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We purchase natural gas supplies in the open market by contracting with producers and marketers, and we maintain a diversified portfolio of natural gas supply contracts. Supplier, producing region, quantity, and available transportation diversify our natural gas supply base. We obtain our natural gas supply from various sources in different geographic areas (Gulf Coast, Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Gas supply pricing is generally tied to NYMEX and published price indices to approximate current market prices.
Properties
We own distribution, transmission and storage properties that are located in the State of Michigan. Our distribution system includes approximately 19,000 miles of distribution mains, approximately 1,193,0001,181,000 service lines and approximately 1,316,0001,324,000 active meters. We own approximately 2,4002,000 miles of transmission lines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas. We also own four carbon dioxide processing facilities.
We own properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 129132 Bcf. These facilities are important in providing reliable and cost-effective service to our customers. In addition, we sell storage services to third parties. Most of our distribution and transmission property is located on property owned by others and used by us through easements, permits or licenses. Substantially all of our property is subject to the lien of a mortgage.
We are directly connected to interstate pipelines, providing access to most of the major natural gas producing regions in the Gulf Coast, Mid-Continent and Canadian regions.
Our primary long-term transportation contracts are as follows:
| Availability (MMcf/d) | Contract expiration | Availability(MMcf/d) | Contract Expiration | |||||||||||||
| Panhandle Eastern Pipeline Company | 75 | 2009 | ||||||||||||||
| Trunkline Gas Company | 10 | 2009 | 10 | 2009 | ||||||||||||
| Viking Gas Transmission Company | 51 | 2010 | 51 | 2010 | ||||||||||||
| TransCanada PipeLines Limited | 53 | 2010 | 53 | 2010 | ||||||||||||
| Great Lakes Gas Transmission L.P. | 30 | 2011 | 30 | 2011 | ||||||||||||
| ANR Pipeline Company | 245 | 2011 | 245 | 2011 | ||||||||||||
| Vector Pipeline L.P. | 50 | 2012 | 50 | 2012 | ||||||||||||
| Panhandle Eastern Pipeline Company | 75 | 2029 | ||||||||||||||
We own 831830 miles of transportation and gathering (non-utility) pipelines in the northern lower peninsula of Michigan. Our Hawes pipeline project is currently under construction and will add an additional 10 miles of pipeline when completed in early 2009. We lease a portion of our pipeline system to the Vector Pipeline Partnership (an affiliate) through a capital leasecapital-lease arrangement. See Note 14 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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Regulation
We are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and other operating-related matters. MichCon’s MPSC-approved rates charged to customers have historically been designed to allow for the recovery of costs, plus an authorized rate of return on our investments. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.
See Note 5 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
Energy Assistance Program
Energy assistance programs, funded by the federal government and the State of Michigan, remain critical to MichCon’s ability to control its uncollectible accounts receivable and collections expenses. MichCon’s uncollectible accounts receivable expense is directly affected by the level of government-funded
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assistance its qualifying customers receive. We work continuously with the State of Michigan and others to determine whether the share of funding allocated to our customers is representative of the number of low-income individuals in our service territory.
Strategy and Competition
Our strategy is to be the preferred provider of natural gas in Michigan. As a result of more efficient furnaces and appliances, and customer conservation due to high natural gas prices and economic conditions, we expect future sales volumes to remain at current levels or slightly decline. We continue to provide energy-related services that capitalize on our expertise, capabilities and efficient systems. We continue to focus on lowering our operating costs by improving operating efficiencies.
Competition in the gas business primarily involves other natural gas providers, as well as providers of alternative fuels and energy sources. The primary focus of competition for end user transportation is cost and reliability. Some large commercial and industrial customers have the ability to switch to alternative fuel sources such as coal, electricity, oil and steam. If these customers were to choose an alternative fuel source, they would not have a need for our end-user transportation service. In addition, some of these customers could bypass our pipeline system and have their gas delivered directly from an interstate pipeline. We compete against alternative fuel sources by providing competitive pricing and reliable service, supported by our storage capacity.
Our extensive transmission pipeline system has enabled us to market 500400 to 600500 Bcf annually for intermediate transportation services and storage services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a central geographic location with connections to major Mid-western interstate pipelines that extend throughout the Midwest, eastern United States and eastern Canada.
MichCon’s storage capacity is used to store natural gas for delivery to MichCon’s customers as well as sold to third parties, under a variety of arrangements for periods up to 3three years. Prices for storage arrangements for shorter periods are generally higher, but more volatile than for longer periods. Prices are influenced primarily by market conditions and natural gas pricing.
NON-UTILITY OPERATIONS
Description
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Tons of Coal Shipped (1) | 35 | 34 | 42 | |||||||||
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providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 8087 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facility is a 66 Bcffacilities are high deliverability storage fieldfields having bi-directional interconnections with Vector Pipeline and MichCon providing our customers access to the Chicago, Michigan, other Midwest and Ontario market centers.
Our customers include various utilities, pipelines, and producers and marketers.
Properties
The Pipelines, Processing and StorageGas Midstream business holds the following property:
Property Classification | % Owned | Description | Location | |||||
| Pipelines | ||||||||
| Vector Pipeline | 40% | 348-mile pipeline with 1,200 MMcf per day capacity | Midwest | |||||
| Millennium Pipeline (in service December 2008) | 26% | |||||||
| 182-mile pipeline with 525 MMcf per day capacity | New York | |||||||
| Storage | ||||||||
| 100% | 71 Bcf of storage capacity | Macomb Co, MI | ||||||
| Washington 28 | 50% | 16 Bcf of storage capacity | ||||||
The assets of these businesses are well integrated with other DTE Energy operations. Pursuant to an operating agreement, MichCon provides physical operations, maintenance, and technical support for the Washington 28 and Washington 10 storage facilities.
Strategy and Competition
Our Coal Transportation and Marketing business is one of the leading North American coal marketers. We have a reputation as an efficient manager of transportation assets. Trends such as railroad and mining consolidation and the lack of certainty in developing new mines by many mining firms could have an impact on how we compete in the future. 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. A portion of our Coal Transportation and Marketing revenues and net income were dependent upon our Synfuel operations that ceased at the end of 2007. We will seek to build our capacity to transport greater amounts of western coal and we have expanded our coal storage and blending capacity with the start of commercial operation of our coal terminal in Chicago in April 2007. Beyond 2008, we expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments.
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Unconventional Gas Production
Description
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas. OnIn June 29, 2007, we sold our Antrim shale gas exploration and production business in the northern lower peninsula of Michigan for gross proceeds of $1.262 billion. OnIn January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to standard post-closing adjustments.$260 million. The properties in the 2008 sale include 18675 Bcfe of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale.
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In 2007,2008, we added proved reserves of 4823 Bcfe in the Barnett shale (15 Bcfe of which is classified as held for sale), resulting in year-end total proved reserves of 219 Bcfe, of which 75 Bcfe were sold in January 2008.167 Bcfe. The Barnett shale wells yielded 7.75 Bcfe of production in 2007.2008. Barnett shale leasehold acres increased to 63,54162,395 gross acres (58,742(60,435 net of interest of others), after adjustment for the January 2008 sale. excluding impairments. We drilled a total of 5437 wells (50 net of interest of others) in the Barnett shale acreage with a success rate of 100% in 2007. Included were five testacreage.
Our Barnett Shale gas production requires processing to extract natural gas liquids. Therefore, our wells (4.8 net of interest of others) in unproved areas of the southernare dedicated to various gathering and western portions of our Barnett shale acreage holdings. While we do not expect further investmentprocessing companies in the southern portion of the Barnett shale, development of our Barnett western acreage is ongoing and will continue in 2008.Fort Worth Basin. The revenues received for all products are sold at prevailing market based prices.
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Properties
Unconventional Gas Production owns interests in the following producing wells and acreage in the Barnett shale as of December 31:
| 2007 | 2006 | 2005 | ||||||||||||||||||||||
| Gross | Net (1) | Gross | Net(1) | Gross | Net (1) | |||||||||||||||||||
Producing Wells and Acreage Producing Wells (2) (6) | ||||||||||||||||||||||||
| Barnett shale (3) | 120 | 120 | 83 | 83 | 47 | 47 | ||||||||||||||||||
| Core shale held for sale | 53 | 33 | 41 | 27 | 18 | 8 | ||||||||||||||||||
| 173 | 153 | 124 | 110 | 65 | 55 | |||||||||||||||||||
Developed Lease Acreage (4) (6) | ||||||||||||||||||||||||
| Barnett shale (3) | 9,922 | 9,880 | 10,759 | 10,693 | 13,018 | 13,018 | ||||||||||||||||||
| Core shale held for sale | 7,379 | 4,987 | 5,679 | 3,977 | 2,506 | 1,349 | ||||||||||||||||||
| 17,301 | 14,867 | 16,438 | 14,670 | 15,524 | 14,367 | |||||||||||||||||||
Undeveloped Lease Acreage (5) (6) | ||||||||||||||||||||||||
| Barnett shale (3) | 38,793 | 38,066 | 30,649 | 27,613 | 13,839 | 13,495 | ||||||||||||||||||
| Core shale held for sale | 7,447 | 5,809 | 7,073 | 6,164 | 9,639 | 7,801 | ||||||||||||||||||
| 46,240 | 43,875 | 37,722 | 33,777 | 23,478 | 21,296 | |||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| Gross | Net(1) | Gross | Net(1) | Gross | Net(1) | |||||||||||||||||||
Producing Wells(2) | ||||||||||||||||||||||||
| Barnett shale(3) | 156 | 155 | 120 | 120 | 83 | 83 | ||||||||||||||||||
| Held for sale | — | — | 53 | 33 | 41 | 27 | ||||||||||||||||||
| 156 | 155 | 173 | 153 | 124 | 110 | |||||||||||||||||||
Developed Lease Acreage(4) | ||||||||||||||||||||||||
| Barnett shale(3) | 14,322 | 14,248 | 9,922 | 9,880 | 10,759 | 10,693 | ||||||||||||||||||
| Held for sale | — | — | 7,379 | 4,987 | 5,679 | 3,977 | ||||||||||||||||||
| 14,322 | 14,248 | 17,301 | 14,867 | 16,438 | 14,670 | |||||||||||||||||||
Undeveloped Lease Acreage(5) | ||||||||||||||||||||||||
| Barnett shale(3) | 48,073 | 46,187 | 38,793 | 38,066 | 30,649 | 27,613 | ||||||||||||||||||
| Held for sale | — | — | 7,447 | 5,809 | 7,073 | 6,164 | ||||||||||||||||||
| 48,073 | 46,187 | 46,240 | 43,875 | 37,722 | 33,777 | |||||||||||||||||||
| (1) | Excludes the interest of others. | |
| (2) | Producing wells are the number of wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. | |
| (3) | Excludes | |
| (4) | Developed lease acreage is the number of acres that are allocated or assignable to productive wells or wells capable of production. | |
| (5) | Undeveloped lease acreage is the number of acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves. | |
Strategy and Competition
We manage and operate our Barnett shale gas properties to maximize returns on investment and increase earnings with the overriding goal of optimizing the cost of producing reserves and adding additional proved reserves. We will consider potential periodic monetizations where market conditions are appropriate.
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From time to time, we use financial derivative contracts to manage a portion of our exposure to changes in the price of natural gas on our forecasted natural gas sales. The following is a summary of the financial contracts in place at December 31, 2008 related to Barnett shale production:
| 2009 | 2010 | |||||||
Long-term fixed price obligations | ||||||||
| Volume- Bcf | 2.0 | 1.2 | ||||||
| Price- $/Mcf | $ | 7.42 | $ | 7.16 | ||||
| 2008 | 2009 | 2010 | ||||||||||
Long-term fixed price obligations | ||||||||||||
Barnett | ||||||||||||
| Volume- Bcf | 2.3 | 2.0 | 1.2 | |||||||||
| Price- $/Mcf | $ | 7.70 | $ | 7.42 | $ | 7.16 | ||||||
We plancontinue to retaininvest in our holdings in the Western portion of the Barnett shale and anticipate significant opportunities to develop our current position while accumulating additional acreage in and around our existing assets.
Current natural gaseconomic conditions and depressed commodity prices have created challenges and successes within the Barnett shale are resulting in additional capital being invested into the area. The competition for goods and services may result in increased operating costs. However, our experienced Barnett shale personnel provide an advantage in addressing potential cost increases. We invested approximately $140 millionopportunities in the Barnett shale in 2007.shale. While operating margins are expected to be lower than 2008, opportunities exist to reduce operating, drilling and completion costs primarily due to the increased availability of drilling rigs and oil field service companies.
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In 2008,2009, we expect to drill approximately 3015 to 4025 wells in the Barnett shale. Investment for the area is expected to be approximately $90 million to $100$25 million during 2008. Successful testing on unproved acreage may yield additional significant investment opportunities.2009.
Power and Industrial Projects
Description
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type services to steel, automotive and other industrial, commercial and institutional customers,customers; provide coal transportation and marketing; and develop biomass energy projects. This business segment provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries.
These services include pulverized coal, petroleum coke and petroleummetallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. At December 31, 2007, this segment ownedWe own and operatedoperate one gas-fired peaking electric generating plant, and atwo biomass-fired electric generating plantplants and operatedoperate one coal-fired power plant under contract. This segment develops, owns and operates landfill gas recovery systems throughout the United States. In addition, this segment produces metallurgical coke from two coke batteries. The production of coke from these coke batteries generates production tax credits.
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| Facility | Location | % Owned | Service Type | |||||||||
Steel | ||||||||||||
| DTE PCI Enterprises Company | River Rouge, MI | 100 | % | (1 | ) | Pulverized Coal | ||||||
| DTE Sparrows Point | Sparrows Point, MD | 100 | % | (1 | ) | Pulverized Coal | ||||||
| EES Coke Battery, LLC | River Rouge, MI | 100 | % | (1 | ) | Metallurgical Coke Supply | ||||||
| Indiana Harbor Coke Co., LP | East Chicago, IN | 5 | % | (1 | ) | Metallurgical Coke Supply | ||||||
Automotive | ||||||||||||
| DTE Energy Center | Various sites in MI, IN, OH | 50 | % | Electric Distribution, Chilled Water, Waste Water, Compressed Air, Mist and Dust Collectors | ||||||||
| DTE Northwind | Detroit, MI | 100 | % | (1 | ) | Steam and Chilled Water | ||||||
| DTE Moraine | Moraine, OH | 100 | % | (1 | ) | Compressed Air | ||||||
| DTE Tonawanda | Tonawanda, NY | 100 | % | (1 | ) | Chilled and Waste Water | ||||||
| DTE Defiance | Defiance, OH | 100 | % | (1 | ) | Steam, Cooling Tower Water, Chilled Water, Compressed Air | ||||||
| DTE Heritage | Dearborn, MI | 100 | % | (1 | ) | Electric Distribution | ||||||
| DTE Dearborn | Dearborn, MI | 100 | % | Steam, Chilled Water, Compressed Air, Waste Water | ||||||||
| DTE Pontiac North | Pontiac, MI | 100 | % | (1 | ) | Electric Generation and Steam | ||||||
| DTE Lordstown | Lordstown, OH | 100 | % | (1 | ) | Steam, Chilled Water, Compressed Air and Reverse Osmosis Water | ||||||
Pulp and Paper | ||||||||||||
| Mobile Energy Services | Mobile, AL | 50 | % | Electric Generation and Steam | ||||||||
Airport | ||||||||||||
| Metro Energy | Romulus, MI | 100 | % | (1 | ) | Electricity, Hot and Chilled Water | ||||||
| DTE Pittsburgh | Pittsburgh, PA | 100 | % | (1 | ) | Hot and Chilled Water | ||||||
Other Industries | ||||||||||||
| DTE PetCoke | Vicksburg, MS | 100 | % | Pulverized Petroleum Coke | ||||||||
January 2010. Production tax credits related to onetwo of the coke battery that expired in 2002facilities were reinstated for the years 2006 through 2009. The coke battery facilities produce coke that is used in blast furnaces within the steel industry. Detroit Edison provides operations and maintenance services for the pulverized coal facility located at Detroit Edison’s River Rouge power plant.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
Production Tax Credits Generated | ||||||||||||
| Allocated to DTE Energy | $ | 5 | $ | 6 | $ | 2 | ||||||
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| Capacity | ||||||||||||
| Facility (1) | Location | % Owned | (in MW) | |||||||||
| | | | | ||||||||||||
| DTE East China | East China Twp, MI | 100 | % | 320 | ||||||||
| Woodland Biomass | Woodland, CA | 99 | % | 25 | ||||||||
| 345 | ||||||||||||
We also provide coal transportation services including fuel, transportation, storage, blending and rail equipment management services. Our external customers include electric utilities, merchant power producers, integrated steel mills and large industrial companies with significant energy requirements. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. We own and operate a coal transloading terminal in South Chicago, Illinois.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
Production Tax Credits Generated | ||||||||||||
| Allocated to DTE Energy | $ | 2 | $ | 1 | $ | — | ||||||
We develop, own and operate landfill gas recovery systems inthroughout the U.S.United States. Landfill gas, a byproduct of solid waste decomposition, is composed of approximately equal portions of methane and carbon dioxide. We develop landfill gas recovery systems that capture the gas and provide local utilities, industry and consumers with an opportunity to use a competitive, renewable source of energy, in addition to providing environmental benefits by reducing greenhouse gas emissions. This business segment performs coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users or for small power generation projects. We also co-own, with the Coal Transportation and Marketing segment,own a coal mine methane gathering system and gas processing facility in southern Illinois. This processed methane is sold into the natural gas transmission system. Manyfacility.
Discontinuance of Planned Monetization of a Portion of our facilities generated production tax credits that expired atPower and Industrial Projects Business— During the endthird quarter of 2007.2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. During 2008, the United States asset sale market weakened and challenges in
| (Dollars in Millions) | 2007 | 2006 | 2005 | |||||||||
| Landfill Sites | 28 | 26 | 32 | |||||||||
| Gas Produced (in Bcf) | 23.5 | 22.9 | 20.2 | |||||||||
| Tax Credits Generated (1) | $ | 3 | $ | 5 | $ | 8 | ||||||
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the debt market persisted. As a result of these developments, our work on this planned monetization was discontinued.
Properties
The following are significant properties operated by the Power and Industrial projects segment:
Facility | Location | % Owned | Service Type | |||||
Steel | ||||||||
| DTE PCI Enterprises Company | River Rouge, MI | 100% | Pulverized Coal | |||||
| DTE Sparrows Point | Sparrows Point, MD | 100% | Pulverized Coal | |||||
| EES Coke Battery | River Rouge, MI | 100% | Metallurgical Coke Supply | |||||
| DTE Shenango | Pittsburgh, PA | 100% | Metallurgical Coke Supply | |||||
| Indiana Harbor Coke Co., | East Chicago, IN | 14.8% | Metallurgical Coke Supply | |||||
Automotive | ||||||||
| DTE Energy Center | Various sites in | 50% | Electric Distribution, Chilled | |||||
| MI, IN, OH | Water, Waste Water, Compressed Air, Mist and Dust Collectors | |||||||
| DTE Northwind | Detroit, MI | 100% | Steam and Chilled Water | |||||
| DTE Moraine | Moraine, OH | 100% | Compressed Air | |||||
| DTE Tonawanda | Tonawanda, NY | 100% | Chilled and Waste Water | |||||
| DTE Defiance | Defiance, OH | 100% | Steam, Cooling Tower Water, Chilled Water, Compressed Air | |||||
| DTE Heritage | Dearborn, MI | 100% | Electric Distribution | |||||
| DTE Dearborn | Dearborn, MI | 100% | Steam, Chilled Water, Compressed Air, Waste Water | |||||
| DTE Pontiac North | Pontiac, MI | 100% | Electric Generation and Steam | |||||
| DTE Lordstown | Lordstown, OH | 100% | Steam, Chilled Water, Compressed Air, and Reverse Osmosis Water | |||||
Pulp and Paper | ||||||||
| Mobile Energy Services | Mobile, AL | 50% | Electric Generation and Steam | |||||
Airport | ||||||||
| Metro Energy | Romulus, MI | 100% | Electricity, Hot and Chilled Water | |||||
| DTE Pittsburgh | Pittsburgh, PA | 100% | Hot and Chilled Water | |||||
Other Industries | ||||||||
| DTE PetCoke | Vicksburg, MS | 100% | Pulverized Petroleum Coke | |||||
Power Generation | ||||||||
| DTE East China (320MW) | East China Twp, MI | 100% | Natural Gas Generating Plant | |||||
| Woodland Biomass (25MW) | Woodland, CA | 99% | Wood Fired Power Plant | |||||
| DTE Stoneman (40MW) | Cassville, WI | 100% | Biomass Power Plant | |||||
Coal Transportation and Marketing | ||||||||
| DTE Chicago Fuels Terminal | Chicago, IL | 100% | Coal Terminal and Blending Plant | |||||
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Landfill Gas Recovery
| 2008 | 2007 | 2006 | ||||||||||
| Landfill Sites | 23 | 28 | 26 | |||||||||
| Gas Produced (in Bcf) | 18.6 | 23.5 | 22.9 | |||||||||
Coal Transportation and Marketing
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Tons of Coal Shipped(1) | 18 | 35 | 34 | |||||||||
| (1) |
Production Tax Credits Generated (Allocated to DTE Energy) | 2008 | 2007 | 2006 | |||||||||||||
| (In millions) | ||||||||||||||||
| Coke Battery | $ | 5 | $ | 5 | $ | 6 | ||||||||||
| Power Generation | 2 | 2 | 1 | |||||||||||||
| Landfill Gas Recovery | — | 3 | 5 | |||||||||||||
Strategy and Competition
Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow our steel; renewable power;on-site energy business. energy; coal transportation, marketing, storage and blending; and landfill gas recovery businesses. We also will continue to pursue opportunities to provide asset management and operations services to third parties.
We anticipate building around our core strengths in the markets where we operate. In determining the markets in which to compete, we examine closely the regulatory and competitive environment, the number of competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue growth opportunities, our first priority will be to achieve value-added returns.
We intend to focus on the following areas for growth:
| • | Providing operating services to owners of industrial and power plants; and | ||
| • | Acquiring and developing solid fuel-fired power plants, | ||
Due to a weakened U.S. economy including constricted capital and credit markets, we expect significantly lower demand for steel in 2009 impacting the financial performance of our coke battery and pulverized coal operations. In addition, the automotive sector has been severely impacted by the current economic situation and has resulted in curtailment of production and plant closings. We will continue to monitor the steel and automotive industries closely during 2009.
Our Coal Transportation and Marketing business is one of the leading North American coal marketers. Trends such as railroad and mining consolidation and the lack of certainty in developing new mines by many mining firms could have an impact on how we compete in the future. In 2011, our existing long-term rail transportation contract which gives us a competitive advantage will expire. We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers. We will seek to build our capacity to transport, store and blend greater amounts of coal and expect to continue to grow our business in a manner consistent with, and complementary to, the growth of our other business segments.
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Energy Trading
Description
Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, the optimization of contracted natural gas pipelinespipeline transportation and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earningsthe recognition of unrealized gains and losses from changes in the fair value of the derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.
Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipelines and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas thehowever gas inventory, power transmission, pipelines and certain storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.
Strategy and Competition
Our strategy for ourthe energy trading business is to deliver value-added services to our customers. We seek to manage this business in a manner consistent with and complementary to the growth of our other business segments. We focus on physical marketing and the optimization of our portfolio of energy assets. We compete with electric and gas marketers, traders, utilities and other energy providers. The trading business is dependent upon the availability of capital and an investment grade credit rating. A material credit restriction would negatively impact our financial performance. Competitors with greater access to capital or at a lower cost may have a competitive advantage. We have risk management and credit processes to monitor and mitigate risk.
CORPORATE & OTHER
Description
Corporate & Other includes various corporate staff functions. Because these functions support the entire Company, their costs are fully allocated to the various segments based on services utilized. Therefore, the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Otherholding company activities and holds certain non-utility debt and energy-related investments.
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DISCONTINUED OPERATIONS
Synthetic Fuel
Description
The Synthetic Fuel business was presented as a non-utility segment through the third quarter of 2007. Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and has beenwas classified as a discontinued operation as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. To optimize income and cash flow from the synfuel operations, we had sold interests in all nine of the facilities, representing 91% of the total production capacity as of December 31, 2007.capacity. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits.
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The value of a production tax credit iswas adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS). The value isof production tax credits for synthetic fuel was reduced ifwhen the Reference Price of a barrel of oil exceedsexceeded certain thresholds. The actual tax credit phase-out for 2007 will not be certain until the Reference Price is published by the IRS in April 2008.
| 2007 | 2006 | |||||||
| (In millions) | ||||||||
Production Tax Credits Generated | ||||||||
| Allocated to DTE Energy | $ | 21 | $ | 23 | ||||
| Allocated to partners | 186 | 260 | ||||||
| $ | 207 | $ | 283 | |||||
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
Production Tax Credits Generated | ||||||||||||
| Allocated to DTE Energy | $ | 21 | $ | 23 | $ | 45 | ||||||
| Allocated to partners | 186 | 260 | 562 | |||||||||
| $ | 207 | $ | 283 | $ | 607 | |||||||
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ENVIRONMENTAL MATTERS
We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers. The following table summarizes our estimated significant future environmental expenditures based upon current regulations:
| (in Millions) | Electric | Gas | Non- Utility | Total | ||||||||||||
| Air | $ | 2,441 | $ | — | $ | — | $ | 2,441 | ||||||||
| Water | 55 | — | 15 | 70 | ||||||||||||
| MGP Sites | 4 | 40 | — | 44 | ||||||||||||
| Other Clean Up Sites | 11 | 2 | — | 13 | ||||||||||||
| Estimated total future expenditures through 2018 | $ | 2,511 | $ | 42 | $ | 15 | $ | 2,568 | ||||||||
| Estimated 2008 expenditures | $ | 288 | $ | 6 | $ | 11 | $ | 305 | ||||||||
| Electric | Gas | Non-Utility | Total | |||||||||||||
| (In millions) | ||||||||||||||||
| Air | $ | 2,800 | $ | — | $ | — | $ | 2,800 | ||||||||
| Water | 55 | — | 1 | 53 | ||||||||||||
| MGP sites | 3 | 38 | — | 41 | ||||||||||||
| Other sites | 9 | 1 | — | 10 | ||||||||||||
| Estimated total future expenditures through 2018 | $ | 2,867 | $ | 39 | $ | 1 | $ | 2,904 | ||||||||
| Estimated 2009 expenditures | $ | 100 | $ | 3 | $ | 1 | $ | 104 | ||||||||
Air —- Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In MarchSince 2005, EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. The cost to address environmental air issues is estimated through 2018.
Water —- In response to an EPA regulation, Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of studies to be conducted over the next several years, Detroit Edison may be required to perform some mitigation activities, including the possible installation of additional control technologies to reduce the environmental impact of the intake structures. However, a recentJanuary 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation, resulting in a delay in complying with the regulation. In 2008, the U.S. Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule. A decision is expected in the first quarter of 2009. Concurrently, the EPA continues to develop a revised rule, which is expected to be published in early 2009.
Manufactured Gas Plant (MGP) and Other Sites —- Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. The facilities, which produced gas for heating and other uses, have been designated as MGP sites. Gas Utility owns, or previously owned, fifteen such former MGP sites. In addition to the MGP sites, we are also in the process of cleaning up other contaminated sites. Detroit Edison conducted remedial investigations at contaminated sites, including three MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. As a result of these determinations, we have recorded liabilities related to these sites. Cleanup activities associated with these sites will be conducted over the next several years.
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Non-utility —Our non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. We are in the process of installing new environmental equipment at our coke battery facility in Michigan. We expect the project to be completed within two years.in the first half of 2009. Our non-utility affiliates are substantially in compliance with all environmental requirements.
21
Global Climate Change —Proposals for voluntary initiatives and mandatory controls are being discussed in the United States to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. There may be legislative and or regulatory action to address the issue of changes in climate that may result from the build up of greenhouse gases, including carbon dioxide, in the atmosphere. We cannot predict the impact any legislative or regulatory action may have on our operations and financial position.
See Notes 5 and 1617 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
EMPLOYEES
We had 10,471 employees as of December 31, 2007:2008, of which 5,331 were represented by unions. The majority of our union employees are under contracts that expire in June and October 2010 and August 2012.
| Represented | Non-represented | Total | ||||||||||
| Detroit Edison | 2,847 | 1,827 | 4,674 | |||||||||
| DTE Energy Corporate Services, LLC | 1,064 | 1,921 | 2,985 | |||||||||
| MichCon | 1,026 | 377 | 1,403 | |||||||||
| Other | 311 | 889 | 1,200 | |||||||||
| Total | 5,248 | 5,014 | 10,262 | |||||||||
EXECUTIVE OFFICERS OF DTE ENERGY
| Present | ||||||||||
| Position | ||||||||||
Name | Age(1) | Present Position | Held Since | |||||||
| | ||||||||||
| Anthony F. Earley, Jr. | 59 | Chairman of the Board and Chief Executive Officer | 8-1-98 | |||||||
| Gerard M. | 50 | Chief Operating Officer and | 10-31-05 | |||||||
| President | 6-23-04 | |||||||||
| David E. Meador(2) | 51 | Executive Vice President and Chief Financial Officer | 6-23-04 | |||||||
| 57 | Senior Vice President and Chief Information Officer | 12-31-01 | ||||||||
| Paul C. Hillegonds(3) | 59 | Senior Vice President | 5-16-05 | |||||||
| Steve E. Kurmas(2) | 52 | President and Chief Operating Officer, Detroit Edison | 12-08-08 | |||||||
| and Group President, DTE Energy | 12-08-08 | |||||||||
| Bruce D. Peterson | 52 | Senior Vice President and General Counsel | 6-25-02 | |||||||
| Gerardo Norcia(2) | 45 | President and Chief Operating Officer, MichCon and | 6-28-07 | |||||||
| Group President, DTE Energy | ||||||||||
| 6-28-07 | ||||||||||
| Larry E. Steward | 56 | Vice President | 1-15-01 | |||||||
| Peter B. | 42 | Vice President and Controller | 2-07-07 | |||||||
| Sandra K. | 52 | Corporate Secretary | 8-4-05 | |||||||
| (1) | As of December 31, | |
| (2) | These executive officers held various positions at DTE Energy for at least five or more years. | |
| (3) | For eight years prior to joining DTE Energy, Mr. Hillegonds was president of Detroit Renaissance, a private, non-profit executive leadership organization dedicated to the growth of the southeast Michigan economy. |
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Under our Bylaws, the officers of DTE Energy are elected annually by the Board of Directors at a meeting held for such purpose, each to serve until the next annual meeting of directors or until their respective successors are chosen and qualified. With the exception of Mr. Hillegonds, all of the above officers have been employed by DTE Energy in one or more management capacities during the past five years.
Pursuant to Article VI of our Articles of Incorporation, directors of DTE Energy will not be personally liable to us or our shareholders in the performance of their duties to the full extent permitted by law.
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Article VII of our Articles of Incorporation provides that each current or former director or officer of DTE Energy, or each current and former employee or agent of the Company or a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (including the heirs, executors, administrators or estate of such person), shall be indemnified by us to the full extent permitted by the Michigan Business Corporation Act or any other applicable laws as presently or hereafter in effect. In addition, we have entered into indemnification agreements with all of our officers and directors; these agreements set forth procedures for claims for indemnification as well as contractually obligating us to provide indemnification to the maximum extent permitted by law.
We and our directors and officers in their capacities as such are insured against liability for alleged wrongful acts (to the extent defined) under eight insurance policies providing aggregate coverage in the amount of $185 million.
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| Item 1A. | Risk Factors |
There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we are providing a brief explanation of the more significant risks associated with our businesses. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.
Regional and national economic conditions can have an unfavorable impact on us. Our utility and non-utility businesses follow the economic cycles of the customers we serve. Our utilities and certain non-utility businesses provide services to the domestic automotive industry which is under considerable financial distress, exacerbating the decline in regional economic conditions. Should national or regional economic conditions further decline, reduced volumes of electricity and gas, and demand for energy services we supply, collections of accounts receivable and potentially higher levels of lost or stolen gas will result in decreased earnings and cash flow.
Adverse changes in our credit ratings may negatively affect us. Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets and could result in an increase in our borrowing costs, a reduced level of capital expenditures and could impact future earnings and cash flows. In addition, a reduction in credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which would impact our liquidity.
Our ability to access capital markets at attractive interest rates is important. Our ability to access capital markets is important to operate our businesses. In recent months, the global financial markets have experienced unprecedented instability. This systemic marketplace distress is impacting our access to capital and cost of capital. This recent turmoil in credit markets has constrained, and may again in the future constrain, our ability as well as the ability of our subsidiaries to issue new debt, including commercial paper, and refinance existing debt. We cannot predict the length of time the current worldwide credit situation will continue or the impact on our future operations and our ability to issue debt at reasonable interest rates. In addition, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. We have substantial amounts of short-term credit facilities that expire in 2009. We intend to seek to renew the facilities on or before the expiration dates. However, we cannot predict the outcome of these efforts, which could result in a decrease in amounts available and/ or an increase in our borrowing costs and negatively impact our financial performance.
Poor investment performance of pension and other postretirement benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations. Our costs of providing non-contributory defined benefit pension plans and other postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, the level of interest rates used to measure
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the required minimum funding levels of the plans, future government regulation, and our required or voluntary contributions made to the plans. The performance of the capital markets affects the value of assets that are held in trust to satisfy future obligations under our plans. We have significant benefit obligations and hold significant assets in trust to satisfy these obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the pension and postretirement benefit plan assets, as was experienced in 2008, will increase the funding requirements under our pension and postretirement benefit plans if the actual asset returns do not recover these declines in the foreseeable future. Additionally, our pension and postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Also, if future increases in pension and postretirement benefit costs as a result of reduced plan assets are not recoverable from Detroit Edison or MichCon customers, the results of operations and financial position of our company could be negatively affected. Without sustained growth in the plan investments over time to increase the value of our plan assets, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our cash flows, financial position, or results of operations.
If our goodwill becomes impaired, we may be required to record a charge to earnings. We annually review the carrying value of goodwill associated with acquisitions made by the Company for impairment. Factors that may be considered for purposes of this analysis include any change in circumstances indicating that the carrying value of our goodwill may not be recoverable such as a decline in stock price and market capitalization, future cash flows, and slower growth rates in our industry. We cannot predict the timing, strength or duration of any economic slowdown or subsequent recovery, worldwide or in the economy or markets in which we operate, however, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, the Company may take a non-cash impairment charge, which could potentially materially impact our results of operations and financial position.
Our participation in energy trading markets subjects us to risk. Events in the energy trading industry have increased the level of scrutiny on the energy trading business and the energy industry as a whole. In certain situations we may be required to post collateral to support trading operations, which could be substantial. If access to liquidity to support trading activities is curtailed, we could experience decreased earnings potential and cash flows.
We are exposed to credit risk of counterparties with whom we do business. Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial position, or results of operations.
We may not be fully covered by insurance. We have a comprehensive insurance program in place to provide coverage for various types of risks, catastrophic damage as a result of acts of God, terrorism, war or a combination of other significant unforeseen events that could impact our operations. Economic losses might not be covered in full by insurance or our insurers may be unable to meet contractual obligations.
We are subject to rate regulationregulation.. Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers’ rates. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or require us to incur additional expenses.
Michigan’s electric Customer Choice program could negatively impact our financial performanceperformance.. The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those
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customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. Recent MPSC rate orders have removed someand recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity.disparity over five years and have placed a cap on the total potential Customer Choice related migration. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. EvenHowever, even with the electric Customer Choice-related rate relief received in recent Detroit Edison’s 2004Edison rate orders and 2005 orders,the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be considerable financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases. The hybrid market in Michigan also causes uncertainty as it relates to investment in new generating capacity.
Weather significantly affects operationsoperations..Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Ice storms, tornadoes, or high winds can damage the electric distribution system infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be fully recoverable through the regulatory process.
Operation of a nuclear facility subjects us to risk.Ownership of an operating nuclear generating plant subjects us to significant additional risks. These risks include, among others, plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.
The supply and price of fuel and other commodities and related transportation costs may impact our financial results.We are dependent on coal for much of our electrical generating capacity. Price fluctuations, and fuel supply disruptions and increases in transportation costs could have a negative impact on our ability to profitably generate electricity. Our access to natural gas supplies is critical to ensure reliability of service for our utility gas customers. We have hedging strategies and regulatory recovery mechanisms in place to mitigate negative fluctuations in commodity supply prices, but there can be no assurances that our financial performance will not be negatively impacted by price fluctuations. The price of natural gas also impacts the market for our non-utility businesses that compete with utilities and alternative electric suppliers. Increased transportation costs could also impact our non-utility businesses.
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Unplanned power plant outages may be costly.Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.
Our estimates of gas reserves are subject to change.We While we cannot provide noabsolute assurance that our estimates of our Barnett gas reserves are accurate.accurate, great care is exercised in utilizing historical information and assumptions to develop reasonable estimates of future production and cash flow. We estimate proved gas reserves and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used.
Our ability to utilize production tax credits may be limited. To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels and electricity from alternative sources. We have generated production tax credits from the synfuel, coke
24
production, landfill gas recovery, biomass fired electric generation and gas production operations. We have received favorable private letter rulings on all of the synfuel facilities. All production tax credits taken after 2003 are subject to audit by the Internal Revenue Service (IRS). If our production tax credits were disallowed in whole or in part as a result of an IRS audit, there could be additional tax liabilities owed for previously recognized tax credits that could significantly impact our earnings and cash flows. We have also provided certain guarantees and indemnities in conjunction with the sales of interests in the synfuel facilities.
We rely on cash flows from subsidiaries.DTE Energy is a holding company. Cash flows from our utility and non-utility subsidiaries are required to pay interest expenses and dividends on DTE Energy debt and securities. Should a major subsidiary not be able to pay dividends or transfer cash flows to DTE Energy, our ability to pay interest and dividends would be restricted.
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Environmental laws and liability may be costly.We are subject to numerous environmental regulations. These regulations govern air emissions, water quality, wastewater discharge, and disposal of solid and hazardous waste. Compliance with these regulations can significantly increase capital spending, operating expenses and plant down times. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections and other regulatory approvals. Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on potentially responsible parties.
We may also incur liabilities as a result of potential future requirements to address climate change issues. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. If increased regulation of greenhouse gas emissions are implemented, the operations of our fossil-fuel generation assets may be significantly impacted.
Since there can be no assurances that environmental costs may be recovered through the regulatory process, our financial performance may be negatively impacted as a result of environmental matters.
Terrorism could affect our businessbusiness.. Damage to downstream infrastructure or our own assets by terrorism would impact our operations. We have increased security as a result of past events and further security increases are possible.
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Benefits of the Performance Excellence Process to uscontinuous improvement initiatives could be less than we expect. We have projected.In 2005, we initiated a company-wide review of our operations called the Performance Excellence Process, with the overarching goalcontinuous improvement program that is expected to become more competitive by reducing costs, eliminating waste and optimizing business processes while improving customer service.result in significant cost savings. Actual results achieved through this processprogram could be less than our expectations.
A work interruption may adversely affect us.Unions represent approximately 5,000 of our employees. A union choosing to strike would have an impact on our business. We are unable to predict the effect a work stoppage would have on our costs of operation and financial performance.
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations.Our business is dependent on our ability to recruit, retain, and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.
| Item 1B. | Unresolved Staff Comments |
None.
| Item 3. | Legal Proceedings |
We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such
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proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.
We are aware of attempts by an environmental organization known as the Waterkeeper Alliance to initiate a criminal action in Canada against the Company for alleged violations of the Canadian Fisheries Act. Fines under the relevant Canadian statute could potentially be significant. To date, the Company has not been properly served process in this matter. Nevertheless, as a result of a decision by a Canadian court, a trial schedule has been initiated. The Company believes the claims of the Waterkeeper Alliance in this matter are without legal merit and ishas appealed the court’s decision. We are not able to predict or assess the outcome of this action at this time.
In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. The defendants filed motions to dismiss. The motions are pending before the court. DTE Energy believes this claim is without merit, but is not able to predict or assess the outcome of this lawsuit at this time.
The City of Detroit Water and Sewer Department (DWSD) has a suit pending in U.S. District Court for the Eastern District of Michigan against EES Coke Battery, LLC (EES Coke), which is an indirect wholly owned subsidiary of the Company, alleging that certain constituents of waste water discharged by EES Coke into DWSD’s sewer system exceeded the permitted amounts. DWSD has requested that EES Coke be required to obtain a new permit and to pay fines for past excess amounts. DWSD and EES Coke have negotiated a consent order to settle this matter that is expected to require EES Coke to pay fines in excess of $100,000. The consent order is subject to final approval of the court. EES Coke is making capital improvements that are intended to prevent exceedances of the permitted amounts in the future.
For additional discussion on legal matters, see Notes 5 and 1617 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
| Item 4. | Submission of Matters to a Vote of Security Holders |
We did not submit any matters to a vote of security holders in the fourth quarter of 2007.2008.
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Part II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is listed on the New York Stock Exchange, which is the principal market for such stock. The following table indicates the reported high and low sales prices of our common stock on the Composite Tape of the New York Stock Exchange and dividends paid per share for each quarterly period during the past two years:
| Dividends | ||||||||||||||||
| Paid | ||||||||||||||||
| Year | Quarter | High | Low | Per Share | ||||||||||||
| 2007 | ||||||||||||||||
First | $ | 49.42 | $ | 45.14 | $ | 0.530 | ||||||||||
Second | $ | 54.74 | $ | 47.22 | $ | 0.530 | ||||||||||
Third | $ | 51.74 | $ | 45.26 | $ | 0.530 | ||||||||||
Fourth | $ | 51.19 | $ | 43.96 | $ | 0.530 | ||||||||||
| 2006 | ||||||||||||||||
| First | $ | 44.23 | $ | 40.00 | $ | 0.515 | ||||||||||
| Second | $ | 41.91 | $ | 38.77 | $ | 0.515 | ||||||||||
| Third | $ | 43.63 | $ | 40.26 | $ | 0.515 | ||||||||||
| Fourth | $ | 49.24 | $ | 41.37 | $ | 0.530 | ||||||||||
| Dividends | ||||||||||||||||
| Paid | ||||||||||||||||
Year | Quarter | High | Low | Per Share | ||||||||||||
| 2008 | ||||||||||||||||
| First | $ | 45.34 | $ | 37.87 | $ | 0.530 | ||||||||||
| Second | $ | 44.82 | $ | 38.95 | $ | 0.530 | ||||||||||
| Third | $ | 44.97 | $ | 38.78 | $ | 0.530 | ||||||||||
| Fourth | $ | 40.92 | $ | 27.82 | $ | 0.530 | ||||||||||
| 2007 | ||||||||||||||||
| First | $ | 49.42 | $ | 45.14 | $ | 0.530 | ||||||||||
| Second | $ | 54.74 | $ | 47.22 | $ | 0.530 | ||||||||||
| Third | $ | 51.74 | $ | 45.26 | $ | 0.530 | ||||||||||
| Fourth | $ | 51.19 | $ | 43.96 | $ | 0.530 | ||||||||||
At December 31, 2007,2008, there were 163,232,095163,019,596 shares of our common stock outstanding. These shares were held by a total of 85,48182,706 shareholders of record.
Our Bylaws nullify Chapter 7B of the Michigan Business Corporation Act (Act). This Act regulates shareholder rights when an individual’s stock ownership reaches 20% of a Michigan corporation’s outstanding shares. A shareholder seeking control of the Company cannot require our Board of Directors to call a meeting to vote on issues related to corporate control within 10 days, as stipulated by the Act.
We paid cash dividends on our common stock of $344 million in 2008, $364 million in 2007, and $365 million in 2006, and $360 million in 2005.2006. The amount of future dividends will depend on our earnings, cash flows, financial condition and other factors that are periodically reviewed by our Board of Directors. Although there can be no assurances, we anticipate paying dividends for the foreseeable future.
See Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Report for information on dividend restrictions.
All of our equity compensation plans that provide for the annual awarding of stock-based compensation have been approved by shareholders. See Note 1819 of the Notes to Consolidated Financial Statements in Item 8 of this Report for additional detail.
See the following table for information as of December 31, 2007.2008.
| Number of securities | Number of securities | |||||||||||
| to be issued upon | Weighted-average | remaining available for | ||||||||||
| exercise of | exercise price of | future issuance under equity | ||||||||||
| outstanding options | outstanding options | compensation plans | ||||||||||
| Plans approved by shareholders | 4,394,809 | $ | 42.37 | 6,289,136 | ||||||||
| Number of Securities | Number of Securities | |||||||||||
| to be Issued Upon | Weighted-Average | Remaining Available For | ||||||||||
| Exercise of | Exercise Price of | Future Issuance Under Equity | ||||||||||
| Outstanding Options | Outstanding Options | Compensation Plans | ||||||||||
| Plans approved by shareholders | 5,013,699 | $ | 42.45 | 4,822,431 | ||||||||
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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table provides information about our purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act for the year ended December 31, 2007:2008:
| Number | ||||||||||||||||||||
| of Shares | Maximum Dollar | |||||||||||||||||||
| Purchased as | Value that May | |||||||||||||||||||
| Number of | Average | Part of Publicly | Average | Yet Be | ||||||||||||||||
| Shares | Price | Announced | Price Paid | Purchased Under | ||||||||||||||||
| Purchased | Paid Per | Plans or | Per Share | the Plans or | ||||||||||||||||
| Period | (1) | Share (1) | Programs (2) | (2) | Programs (2) | |||||||||||||||
| 01/01/07 – 01/31/07 | — | — | — | — | $ | 651,506,040 | ||||||||||||||
| 02/01/07 – 02/28/07 | 20,000 | $ | 47.03 | — | — | 651,506,040 | ||||||||||||||
| 03/01/07 – 03/31/07 | 168,650 | 46.50 | 989,300 | $ | 46.46 | 605,523,194 | ||||||||||||||
| 04/01/07 – 04/30/07 | 75,500 | 48.62 | — | — | 605,523,194 | |||||||||||||||
| 05/01/07 – 05/31/07 | 1,550 | 51.34 | 1,771,000 | 52.23 | 1,362,982,121 | |||||||||||||||
| 06/01/07 – 06/30/07 | — | — | 4,481,832 | 50.01 | 1,138,745,816 | |||||||||||||||
| 07/01/07 – 07/31/07 | 1,000 | 48.60 | 3,208,538 | 49.15 | 980,986,679 | |||||||||||||||
| 08/01/07 – 08/31/07 | 376,250 | 47.89 | 2,474,986 | 47.85 | 862,514,949 | |||||||||||||||
| 09/01/07 – 09/30/07 | — | — | 380,800 | 47.83 | 844,294,092 | |||||||||||||||
| 10/01/07 – 10/31/07 | 7,575 | 49.95 | 401,495 | 47.71 | 825,132,252 | |||||||||||||||
| 11/01/07 – 11/30/07 | 20,000 | 49.09 | 46,689 | 47.88 | 822,895,623 | |||||||||||||||
| 12/01/07 – 12/31/07 | 15,000 | 45.23 | — | — | 822,895,623 | |||||||||||||||
| Total | 685,525 | 13,754,640 | ||||||||||||||||||
| Number | ||||||||||||||||||||
| of Shares | Maximum Dollar | |||||||||||||||||||
| Purchased as | Value that May | |||||||||||||||||||
| Number of | Average | Part of Publicly | Average | Yet Be | ||||||||||||||||
| Shares | Price | Announced | Price Paid | Purchased Under | ||||||||||||||||
| Purchased | Paid Per | Plans or | Per Share | the Plans or | ||||||||||||||||
| (1) | Share (1) | Programs (2) | (2) | Programs (2) | ||||||||||||||||
| 01/01/08 — 01/31/08 | 34,300 | $ | 43.96 | — | — | $ | 822,895,623 | |||||||||||||
| 02/01/08 — 02/29/08 | 203,670 | 41.24 | — | — | 822,895,623 | |||||||||||||||
| 03/01/08 — 03/31/08 | 83,760 | 38.92 | — | — | 822,895,623 | |||||||||||||||
| 04/01/08 — 04/30/08 | 22,220 | 41.46 | — | — | 822,895,623 | |||||||||||||||
| 05/01/08 — 05/31/08 | 32,000 | 43.13 | — | — | 822,895,623 | |||||||||||||||
| 06/01/08 — 06/30/08 | 35,000 | 43.72 | — | — | 822,895,623 | |||||||||||||||
| 07/01/08 — 07/31/08 | 1,200 | 43.07 | — | — | 822,895,623 | |||||||||||||||
| 08/01/08 — 08/31/08 | 20,000 | 42.25 | — | — | 822,895,623 | |||||||||||||||
| 09/01/08 — 09/30/08 | — | — | — | — | 822,895,623 | |||||||||||||||
| 10/01/08 — 10/31/08 | 9,455 | 34.95 | — | — | 822,895,623 | |||||||||||||||
| 11/01/08 — 11/30/08 | 37,464 | 36.91 | — | — | 822,895,623 | |||||||||||||||
| 12/01/08 — 12/31/08 | — | — | — | — | 822,895,623 | |||||||||||||||
| Total | 479,069 | |||||||||||||||||||
| (1) | Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program. | |
| (2) | In January 2005, the DTE Energy Board of Directors authorized the repurchase of up to $700 million of common stock through 2008. In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to an additional $850 million of common stock through 2009. Through December 31, |
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| Item 6. | Selected Financial Data |
The following selected financial data should be read in conjunction with the accompanying Management’s Discussion and Analysis in Item 7 of this Report and Notes to the Consolidated Financial Statements in Item 8 of this Report.
| (in Millions, except per share amounts) | 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||||||||||||||||||||||||||
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||||||||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||||||||||||||||||||||
Operating Revenues | $ | 8,506 | $ | 8,159 | $ | 8,094 | $ | 6,419 | $ | 6,429 | $ | 9,329 | $ | 8,475 | $ | 8,157 | $ | 8,094 | $ | 6,419 | ||||||||||||||||||||
Net Income (Loss) | ||||||||||||||||||||||||||||||||||||||||
| Total from continuing operations (1) | $ | 787 | $ | 389 | $ | 272 | $ | 265 | $ | 275 | ||||||||||||||||||||||||||||||
| Income from continuing operations(1) | $ | 526 | $ | 787 | $ | 389 | $ | 272 | $ | 265 | ||||||||||||||||||||||||||||||
| Discontinued operations | 184 | 43 | 268 | 166 | 273 | 20 | 184 | 43 | 268 | 166 | ||||||||||||||||||||||||||||||
| Cumulative effect of accounting changes | — | 1 | (3 | ) | — | (27 | ) | — | — | 1 | (3 | ) | — | |||||||||||||||||||||||||||
| Net Income | $ | 971 | $ | 433 | $ | 537 | $ | 431 | $ | 521 | $ | 546 | $ | 971 | $ | 433 | $ | 537 | $ | 431 | ||||||||||||||||||||
Diluted Earnings Per Share | ||||||||||||||||||||||||||||||||||||||||
| Total from continuing operations | $ | 4.62 | $ | 2.18 | $ | 1.55 | $ | 1.53 | $ | 1.63 | ||||||||||||||||||||||||||||||
Diluted Earnings Per Common Share | ||||||||||||||||||||||||||||||||||||||||
| Income from continuing operations | $ | 3.23 | $ | 4.62 | $ | 2.18 | $ | 1.55 | $ | 1.53 | ||||||||||||||||||||||||||||||
| Discontinued operations | 1.08 | .24 | 1.52 | .96 | 1.62 | .13 | 1.08 | .24 | 1.52 | .96 | ||||||||||||||||||||||||||||||
| Cumulative effect of accounting changes | — | .01 | (.02 | ) | — | (.16 | ) | — | — | .01 | (.02 | ) | — | |||||||||||||||||||||||||||
| Diluted Earnings Per Share | $ | 5.70 | $ | 2.43 | $ | 3.05 | $ | 2.49 | $ | 3.09 | ||||||||||||||||||||||||||||||
| Diluted Earnings Per Common Share | $ | 3.36 | $ | 5.70 | $ | 2.43 | $ | 3.05 | $ | 2.49 | ||||||||||||||||||||||||||||||
Financial Information | ||||||||||||||||||||||||||||||||||||||||
| Dividends declared per share of common stock | $ | 2.12 | $ | 2.075 | $ | 2.06 | $ | 2.06 | $ | 2.06 | $ | 2.12 | $ | 2.12 | $ | 2.075 | $ | 2.06 | $ | 2.06 | ||||||||||||||||||||
| Total assets | $ | 23,754 | $ | 23,785 | $ | 23,335 | $ | 21,297 | $ | 20,753 | $ | 24,590 | $ | 23,742 | $ | 23,785 | $ | 23,335 | $ | 21,297 | ||||||||||||||||||||
| Long-term debt, including capital leases | $ | 6,971 | $ | 7,474 | $ | 7,080 | $ | 7,606 | $ | 7,669 | $ | 7,741 | $ | 6,971 | $ | 7,474 | $ | 7,080 | $ | 7,606 | ||||||||||||||||||||
| Shareholders’ equity | $ | 5,853 | $ | 5,849 | $ | 5,769 | $ | 5,548 | $ | 5,287 | $ | 5,995 | $ | 5,853 | $ | 5,849 | $ | 5,769 | $ | 5,548 | ||||||||||||||||||||
| (1) | 2007 amounts include $580 million after-tax gain on the Antrim sale transaction and $210 million after-tax losses on hedge contracts associated with the Antrim sale. 2008 amounts include $81 million after-tax gain on the sale of a portion of the Barnett shale properties. See Note 3 of Notes to Consolidated Financial Statements in Item 8 of this Report. |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
DTE Energy is a diversified energy company with 20072008 operating revenues in excess of $8$9 billion and approximatelyover $24 billion in assets. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.
The following table summarizes our financial results:
| (in Millions, except Earnings per Share) | 2007 | 2006 | 2005 | |||||||||
| Income from Continuing Operations | $ | 787 | $ | 389 | $ | 272 | ||||||
| Earnings per Diluted Share | $ | 4.62 | $ | 2.18 | $ | 1.55 | ||||||
| Net Income | $ | 971 | $ | 433 | $ | 537 | ||||||
| Earnings per Diluted Share | $ | 5.70 | $ | 2.43 | $ | 3.05 | ||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions, except earnings per share) | ||||||||||||
| Income from continuing operations | $ | 526 | $ | 787 | $ | 389 | ||||||
| Diluted earnings per common share from continuing operations | $ | 3.23 | $ | 4.62 | $ | 2.18 | ||||||
| Net income | $ | 546 | $ | 971 | $ | 433 | ||||||
| Diluted earnings per common share | $ | 3.36 | $ | 5.70 | $ | 2.43 | ||||||
The increase fordecrease in 2008 from 2007 was primarily due to approximately $370 million in net income resulting from the 2007 gain on the sale of the Antrim shale gas exploration and production business of $900 million ($580 million after-tax), partially offset by losses recognized on related hedges of $323 million ($210 million
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after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income.income during 2007. Net income in 20062008 was adverselyalso impacted by the temporary idlinga gain of synfuel plants along with
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The items discussed below influenced our current financial performance and/orand may affect future results:
| • | Impacts of national and regional economic conditions on utility operations; | ||
| • | Effects of weather | ||
| • | Collectibility of accounts receivable on utility operations; | ||
| • | Impact of regulatory decisions on | ||
| • | Impact of legislation on utility operations; | ||
| • | Fluctuations in market demand on coal supply; | ||
| • | Challenges associated with nuclear fuel; | ||
| • | Monetization of portions of our Unconventional Gas Production business; | ||
| • | |||
| • | Results in our Energy Trading business; | ||
| • | |||
| • |
UTILITY OPERATIONS
Our Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million customers in southeastern Michigan.
Our Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.31.2 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.
Impact of national and regional economic conditions on our utility operations — Revenues from our utility operations follow the economic cycles of the customers we serve. Our utilities provide services to the domestic automotive industry which is under considerable financial distress, exacerbating the decline in regional conditions. In 2008, Detroit Edison experienced a decline in sales in its service territory as compared to 2007. We expect this decline to continue in 2009. As discussed further below, deteriorating economic conditions impact our ability to collect amounts due from our customers of our electric and gas utilities and drive higher levels of lost and stolen natural gas at MichCon. In the face of the economic conditions, we are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength.
Effects of Weather on Utility Operations- — Earnings from our utility operations are seasonal and very sensitive to weather. Electric utility earnings are primarily dependent on hot summer weather, while the gas utility’s results are primarily dependent on cold winter weather. During the year ended December 31, 2008 we experienced colder weather than the year ended December 31, 2007.
Additionally, we frequently experience various types of storms that damage our electric distribution infrastructure, resulting in power outages. Restoration and other costs associated with storm-related power outages lowered pre-tax earnings by $61 million in 2008, $68 million in 2007 and $46 million in 2006 and $82 million in 2005.2006.
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unemployment and home foreclosures. High energy prices and a lack of adequate levels of governmental assistance for low-income customers.customers have also impacted our accounts receivable.
We have taken aggressive actions to reducemanage the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with the State of Michigan officials and others to increase the share of low-income funding allocated to our customers. In 2006, we sold previously written-off accounts of $43 million resulting in a gain and net proceeds of $1.9 million. The gain was recorded as a recovery through doubtful accounts expense, which is included within Operation and maintenance expense.
Our doubtfuluncollectible accounts expense for the two utilities increased to $213 million in 2008 from $135 million in 2007 and from $123 million in 2006 and from $98 million in 2005.2006.
The April 2005 MPSC gas rate order provided for an uncollectibletrue-up mechanism for MichCon. The uncollectibletrue-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. The MPSC approved the 2005 annual reconciliation in December 2006, allowing
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MichCon to surcharge $11 million beginning in January 2007. The MPSC approved the 2006 annual reconciliation in December 2007, allowing MichCon to surcharge $33 million beginning in January 2008. We expectIn December 2008, MichCon received authorization to file the 2007 reconciliation in the first quarter of 2008 requesting an additional surcharge of approximately $33$34 million, including thea $1 million uncollected balance from the 2005 surcharge,. beginning in January 2009. We accrue interest income on the outstanding balances.
Impact of Regulatory activityDecisions on Utility Operations— On December 23, 2008, the MPSC issued an order in Detroit Edison filed a generalEdison’s February 20, 2008 updated rate case on April 13, 2007 based onfiling. The MPSC approved an annual revenue increase of $84 million effective January 14, 2009 or a 2006 historical test year. The filing with the MPSC requested a $123 million, or 2.9 percent,2.0% average increase in Detroit Edison’s annual revenue requirement for 2008. On August 31, 2007, Detroit Edison filed2009. Included in the approved $84 million increase in revenues was a supplement to its April 2007 rate case filing to account for certain recent events. A July 2007 decision by the Courtreturn on equity of Appeals11% on an expected 49% equity and 51% debt capital structure.
Other key aspects of the State of Michigan remanded back toMPSC order include the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. Also, the Michigan legislature enacted the Michigan Business Tax (MBT) in July 2007. The supplemental filing addressed the recovery of the merger control premium costs and the enactment of the MBT. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million. On February 20, 2008, Detroit Edison filed an update to its April 2007 rate case filing. The update reflects the use of 2009 as the projected test year and includes a revised 2009 load forecast, and 2009 estimates on environmental and advanced metering infrastructure capital expenditures, and adjustments to the calculation of the MBT. See Note 5 of the Notes to Consolidated Financial Statements.following:
| • | In order to more accurately reflect the actual cost of providing service to business customers, the MPSC adopted an immediate 39% phase out of the residential rate subsidy, with the remaining amount to be eliminated in equal installments over the next five years, every October 1. | |
| • | Accepted Detroit Edison’s proposal to reinstate and modify the tracking mechanism on Electric Choice sales (CIM) with a base level of 1,561 GWh. The modified mechanism will not have a cap on the amount recoverable. | |
| • | Terminated the Pension Equalization Mechanism. | |
| • | Approved an annual reconciliation mechanism to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $110 million and $51 million, respectively. | |
| • | Approved Detroit Edison’s proposal to recover a return on $15 million in working capital associated with the preparation of an application for a new nuclear generation facility at its current Fermi 2 site. |
The MPSC issued an order on August 31, 2006 approving a settlement agreement providing for an annualized rate reduction of $53 million for 2006 for Detroit Edison, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. Detroit Edison experienced a rate reduction of approximately $76 million in 2007 and approximately $25 million during the period the rate reduction was in effect for 2008, as a result of this order. The revenue reduction iswas net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement providesprovided for some level of realignment of the existing rate structure by allocating a larger percentage of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was approved by the MPSC that provides for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provides for a rate case filing moratorium until January 1, 2009,
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unless certain unanticipated changes occur that impact income by more than $5 million. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, will enablehave enabled 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54$41 million. This settlement providesalso provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon expects to sell in 2007, 2008 and 2009. In the fourth quarter of 2007, MichCon sold .750.75 Bcf of base gas and recognizedin 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. By enablingIn July 2008, MichCon filed an application with the MPSC requesting permission to retainsell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the profitbase gas to GCR customers during the2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of thisthe 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income and not include the settlementproceeds in the calculation of MichCon’s revenue requirements in future rate cases.
Impact of Legislation on Utility Operations — On September 18, 2008, the Michigan House of Representatives and Michigan Senate passed a package of bills to establish a comprehensive, sustainable, long-term energy plan for Michigan. The Governor of Michigan signed the bills on October 6, 2008.
The package of bills includes:
| • | 2008 Public Act (PA) 286 that reforms Michigan’s utility regulatory framework, including the electric Customer Choice program, | |
| • | 2008 PA 295 that establishes a renewable portfolio / energy optimization standard and provides a funding mechanism, and | |
| • | 2008 PA 287 that provides for an income tax credit for the purchase of energy efficient appliances and a credit to offset a portion of the renewable charge. |
2008 PA 286 makes the following changes in the regulatory framework for Michigan utilities.
| • | Electric Customer Choice reform— The bill establishes a 10 percent limit on participation in the electric Customer Choice program. In general, customers representing 10 percent of a utility’s load may receive electric generation from an electric supplier that is not a utility. After that threshold is met, the remaining customers will remain on full, bundled utility service. As of December 31, 2008, approximately 3 percent of Detroit Edison’s load was on the electric Customer Choice program. The bill also allows continuation of prior MPSC policies for customers to return to full utility service. | |
| • | Cost-of-service based electric rates (deskewing)— The bill requires the MPSC to set rates based on cost-of-service for all customer classes, eliminating over a five-year period the current subsidy by businesses of residential customer rates. This provision does not change total revenue for Detroit Edison. It lowers rates for most commercial and industrial customers and increases rates for residential and certain other industrial customers to match the actual cost of service for each customer class. Rate changes will be phased in over five years, with a 2.5% annual cap on residential rate increases due to deskewing beginning January 1, 2009. Rates for schools and other qualified educational institutions will be set at their cost of service sooner. | |
| • | File and use ratemaking— The bill establishes a 12 month deadline for the MPSC to complete a rate case and allows a utility to self-implement rate changes six months after a rate filing, subject to certain limitations. If the final case order leads to lower rates than the utility had self-implemented, the utility will refund with interest, the difference. In addition, utility rate cases may be based on a forward test year. The bill also has provisions designed to help the MPSC obtain increased funding for additional staff. | |
| • | Certificate of Need process for major capital investments— The bill establishes a certificate of need process for capital projects costing more than $500 million. The process requires the MPSC to review for prudence, prior to construction, proposed investments in new generating assets, acquisitions of existing power plants, major upgrades of power plants, and long-term power purchase agreements. The |
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| bill increases the certainty for utilities to recover the cost of projects approved by the MPSC and provides for the utilities to recover interest expenses during construction. |
| • | Merger & Acquisition approval— The bill grants the MPSC the authority to review and approve proposed utility mergers and acquisitions in Michigan and sets out evaluation criteria. |
2008 PA 295 establishes renewable energy and energy optimization (energy efficiency, energy conservation or load management) programs in Michigan and provides MichConfor a separate funding surcharge to pay the cost of those programs. In accordance with the opportunitynew law, the MPSC issued a temporary order on December 4, 2008 implementing this act. Within 90 days following the issuance of the temporary order, Detroit Edison is required to earn an 11% returnfile a Renewable Portfolio Standard (RPS) plan with the MPSC. In addition, Detroit Edison and MichCon are required to file Energy Optimization plans with the MPSC.
Renewable Energy Standard
| • | The bill requires electric providers to source 10% of electricity sold to retail customers from renewable energy resources by 2015. | |
| • | Qualifying renewable energy resources include wind, biomass, solar, hydro, and geothermal, among others. | |
| • | Detroit Edison will be required to have a renewable energy capacity portfolio of 300MW by December 31, 2013 and 600MW by December 31, 2015. | |
| • | The MPSC will establish a per meter surcharge to fund the renewable energy requirements. The recovery mechanism starts prior to actual construction in order to smooth the rate impact for customers. | |
| • | The bill allows for the lowering of compliance if RPS costs exceed the surcharge/cost cap or if other specified factors adversely affect the availability of renewable energy. | |
| • | The bill specifies that a utility can build or have others build and later sell to the utility up to 50 percent of the generation required to meet the RPS. The other 50 percent would be contracted through power purchase agreements. | |
| • | The bill also provides for a net metering program to be established by MPSC order foron-site customer-owned renewable generation up to 1% of an electric utility’s load. |
Energy Optimization Standard
| • | Requires utilities to create electric and natural gas energy optimization plans for each customer class and includes funding surcharges as well as the potential for incentives for exceeding performance goals. | |
| • | For electric sales, the program targets 0.3 percent annual savings in 2009, ramping up to 1 percent annual savings by 2012. Savings percentages are based on prior year retail sales. | |
| • | For natural gas sales, the targeted annual savings start at 0.1 percent in 2009 and ramp up to 0.75 percent by 2012. | |
| • | The MPSC will allow utilities to capitalize certain costs of their energy optimization program. The costs which can be capitalized include equipment, materials, installation costs and customer incentives. | |
| • | Incentives are potentially available for exceeding annual program targets. The financial incentive could be the lesser of 25% of the net cost reduction to our customers or 15% of total program spend, subject to MPSC approval. | |
| • | The bill would also allow a natural gas utility that spends at least 0.5 percent of its revenues on energy efficiency programs to implement a symmetrical decouplingtrue-up mechanism that adjusts for sales volumes that are above or below the level reflected in its gas distribution rates. | |
| • | By March 2016, the MPSC may suspend the program if it determines the program is no longer cost-effective. |
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Impact of Increased Market Demand on equity with no customer rate increase for a period of five years from 2005 to 2010.
Coal Supply- — Our generating fleet produces approximately 79% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in significantvolatility and higher prices which are passed to our customers through the PSCR mechanism. The demand and price increases.volatility have been dampened by the recent economic downturn, but are expected to increase as the economy improves. In addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal hashave resulted in decreasing coal output from the central Appalachian region. Furthermore, as a result of environmental regulation and declining eastern coal stocks, demand for cleaner burning western coal has increased. This increased demand for western coal has also resulted in a corresponding demand for western rail shipping, straining railroad capacity and resulting in longer lead times for western coal shipments.
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Challenges Associated with Nuclear Fuel- — We operate one nuclear facility (Fermi 2) that undergoes a periodic refueling outage approximately every eighteen months. Uranium prices have been rising due to supply concerns. In the future, there may be additional nuclear facilities constructed in the industry that may place additional pressure on uranium supplies and prices. We have a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. We are obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. Thesold; this fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage. We have begun work on an on-site dry cask storage facility. We are 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. Until the DOE is able to fulfill its obligation under the contract, we are responsible for the spent nuclear fuel storage and have begun work on anon-site dry cask storage facility.
NON-UTILITY OPERATIONS
We have made significant investments in non-utility asset-intensive businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. A number of factors have impacted our non-utility businesses, including the effect of oil prices on the synthetic fuel business, losses and impairments from certain power generation assets, waste coal recovery and landfill gas recovery businesses, and earnings volatility in our energy trading business. As part of a strategic review of our non-utility operations, we have taken and continue to pursue various actions including the sale restructuring or recapitalization of certain non-utility businesses that generated approximately $900 million in after-tax cash proceeds in 2007 and is expected to generate an additional $800 million in 2008. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report for information on the sale of our Antrim shale gas exploration and production business in northern Michigan, the sale of a portion of our Barnett shale properties and the pending financing and sale of a 50 percent ownership interest in select projects within the Power and Industrial Projects segment.businesses.
Gas Midstream segment consists of Coal Transportation and Marketing and the Pipelines, Processing and Storage businesses.
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Unconventional Gas Production
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in north Texas.
Monetization of Portions of our Unconventional Gas Production segment recorded pre-tax impairment lossesBusiness — In 2008, we sold a portion of $27 million in 2007, related to the write-offour Barnett shale properties for gross proceeds of unprovedapproximately $260 million. The properties and expirationsold included 75 Bcfe of leases in Bosque County, which is locatedproved reserves on approximately 11,000 net acres in the southern expansioncore area of the Barnett shale basinshale. The Company recognized a cumulative pre-tax gain of $128 million ($81 million after-tax) on the sale during 2008.
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We plan to continue to develop our holdings in north Texas. The properties were impaired due to the lack of economic and operating viabilitywestern portion of the southern expansion area. See Note 4Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $96 million in the NotesBarnett shale in 2008 and expect to Consolidated Financial Statements.invest approximately $25 million in 2009. During 2009, we expect to drill 15 to 25 new wells and achieve Barnett shale production of approximately 5-6 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.
As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of anticipated production from our reserves to secure an attractive investment return. As of December 31, 2007,2008, we have a series of cash flow hedges for approximately 5.53.2 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.48$7.33 per Mcf.
Texas — Barnett shale. On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to post-closing adjustments. The Company will recognize a gain on the sale in the first quarter of 2008. The properties in the sale include 186 billion cubic feet of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale.
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| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| 2007 | 2006 | 2005 | ||||||||||||||||||||||
| Net Producing Wells | ||||||||||||||||||||||||
| Held for sale | 33 | 27 | 8 | — | 33 | 27 | ||||||||||||||||||
| Continuing operations | 120 | 83 | 47 | |||||||||||||||||||||
| Held for use | 155 | 120 | 83 | |||||||||||||||||||||
| Total | 153 | 110 | 55 | 155 | 153 | 110 | ||||||||||||||||||
| Production Volume (Bcfe) | ||||||||||||||||||||||||
| Held for sale | 4.7 | 2.8 | 0.4 | — | 4.7 | 2.8 | ||||||||||||||||||
| Continuing operations | 3.0 | 1.3 | 0.4 | |||||||||||||||||||||
| Held for use | 5.0 | 3.0 | 1.3 | |||||||||||||||||||||
| Total | 7.7 | 4.1 | 0.8 | 5.0 | 7.7 | 4.1 | ||||||||||||||||||
| Proved Reserves (Bcfe) (1) | ||||||||||||||||||||||||
| Proved Reserves (Bcfe)(1) | ||||||||||||||||||||||||
| Held for sale | 75 | 60 | 11 | — | 75 | 60 | ||||||||||||||||||
| Continuing operations | 144 | 111 | 48 | |||||||||||||||||||||
| Held for use | 167 | 144 | 111 | |||||||||||||||||||||
| Total | 219 | 171 | 59 | 167 | 219 | 171 | ||||||||||||||||||
| Net Developed Acreage (1) | ||||||||||||||||||||||||
| Net Developed Acreage(1) | ||||||||||||||||||||||||
| Held for sale | 4,987 | 3,977 | 1,349 | — | 4,987 | 3,977 | ||||||||||||||||||
| Continuing operations (2) | 9,880 | 10,693 | 13,018 | |||||||||||||||||||||
| Held for use(2) | 14,248 | 9,880 | 10,693 | |||||||||||||||||||||
| Total | 14,867 | 14,670 | 14,367 | 14,248 | 14,867 | 14,670 | ||||||||||||||||||
| Net Undeveloped Acreage (1) | ||||||||||||||||||||||||
| Net Undeveloped Acreage(1) | ||||||||||||||||||||||||
| Held for sale | 5,809 | 6,164 | 7,801 | — | 5,809 | 6,164 | ||||||||||||||||||
| Continuing operations (2) | 38,066 | 27,613 | 13,495 | |||||||||||||||||||||
| Held for use(2) | 46,187 | 38,066 | 27,613 | |||||||||||||||||||||
| Total | 43,875 | 33,777 | 21,296 | 46,187 | 43,875 | 33,777 | ||||||||||||||||||
| Capital Expenditures (in Millions) (3) | ||||||||||||||||||||||||
| Capital Expenditures (in Millions)(3) | ||||||||||||||||||||||||
| Held for sale | $ | 45 | $ | 67 | $ | 19 | $ | — | $ | 45 | $ | 67 | ||||||||||||
| Continuing operations | 95 | 61 | 76 | |||||||||||||||||||||
| Held for use | 96 | 95 | 61 | |||||||||||||||||||||
| Total | $ | 140 | $ | 128 | $ | 95 | $ | 96 | $ | 140 | $ | 128 | ||||||||||||
| Future Undiscounted Net Cash Flows (in Millions) (4) | ||||||||||||||||||||||||
| Future Undiscounted Net Cash Flows (in Millions)(4) | ||||||||||||||||||||||||
| Held for sale | $ | 282 | $ | 167 | $ | 63 | $ | — | $ | 282 | $ | 167 | ||||||||||||
| Continuing operations | 521 | 305 | 266 | |||||||||||||||||||||
| Held for use | 324 | 521 | 305 | |||||||||||||||||||||
| Total | $ | 803 | $ | 472 | $ | 329 | $ | 324 | $ | 803 | $ | 472 | ||||||||||||
| Average gas price (per Mcf) | $ | 6.29 | $ | 5.66 | $ | 9.01 | $ | 8.69 | $ | 6.29 | $ | 5.66 | ||||||||||||
| (1) | Due to the impairment of acreage and wells in the southern expansion area of the Barnett shale during 2007, the proved reserves and acreage numbers above do not include the southern area. Total net acreage related to impaired leases in the southern expansion area was 23,659 acres |
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| 2007 and 2006, respectively. In 2008, an impairment was recorded on approximately 5,600 acres within the western expansion of the Barnett Shale. Impaired acreage and | ||
| (2) | Developed acreage for continuing operations shows a decrease from | |
| (3) | Excludes sold and impaired assets in southern expansion area of the Barnett shale. | |
| (4) | Represents the standardized measure of |
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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,customers; provide coal transportation and biomassmarketing; and sell electricity from biomass-fired energy projects. This business segment provides utility-type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. These services
Services provided include pulverized coal, petroleum coke and petroleummetallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. At December 31, 2007, this segment ownedWe own and operatedoperate one gas-fired peaking electric generating plant, and atwo biomass-fired electric generating plants and operate one coal-fired power plant. A third biomass-fired electric generating plant is currently under development pending certain regulatory and management approvals with an expected in-service date of January 2010. This business segment also owned one additional coal-fired power plant that is currently not in service. This segment develops, owns and operates landfill gas recovery systems throughout the United States. In addition, this segmentStates and produces metallurgical coke from twothree coke batteries. The production of coke from thesetwo of the coke batteries generates production tax credits. The business provides coal transportation — related services including fuel, transportation, storage, blending and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal marketing and the purchase and sale of emissions credits. This business segment performs coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines, industrial users or for small power generation projects.
Discontinuance of Planned Monetization of our Power and Industrial Projects Business —During the third quarter of 2007, we announced our plans to sell a 50 percent50% interest in a portfolio of select Power and Industrial Projects. In addition to the proceeds that the Company will receive from the sale of the 50 percent equity interest, the company that will own the projects will obtain debt financing and the proceeds will be distributed to DTE Energy immediately prior to the sale of the equity interest. The total gross proceeds the Company will receive are expected to approximate $650 million. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completion of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operationsassets and liabilities of the Projects were classified as held for sale at that time. During 2008, the United States asset sale market weakened and to act aschallenges in the managing memberdebt market persisted. As a result of these developments, our work on this planned monetization was discontinued. As of June 30, 2008, the assets and liabilities of the company that owns the projects. We plan to accountProjects are no longer classified as held for our 50 percent ownership interest in the company that will own the portfolio of projects using the equity method. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.sale.
Energy Trading
Energy Trading focuses on physical power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio and the optimization of contracted natural gas pipelinespipeline transportation and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in the recognition of unrealized gains and losses from changes in the fair value of the derivatives in our results of operations.derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.
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Significant portions of the electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipelinespipeline transportation and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas theproprietary gas inventory, power transmission, pipelines and certain storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.
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DISCONTINUED OPERATIONS
Synthetic Fuel
The Synthetic Fuel business had been shownwas presented as a non-utility segment through the third quarter of 2007. Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and has been
was classified as a discontinued operation as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. To optimize income and cash flow from the synfuel operations, we had sold interests in all nine of the facilities, representing 91% of the total production capacity as of December 31, 2007.capacity. The synthetic fuel plants generated operating losses that were substantially offset by production tax credits.
The value of a production tax credit iswas adjusted annually by an inflation factor and published annually by the Internal Revenue Service (IRS).IRS. The value isof production tax credits for synthetic fuel was reduced ifwhen the Reference Price of a barrel of oil exceedsexceeded certain thresholds. The actual tax credit phase-out for 2007 will not be certain until the Reference Price is published by the IRS in April 2008.was approximately 67%.
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We anticipate significant capital investment across all of our business segments. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility segment currently expects to invest approximately $5.2$6 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects during the period of 20082009 through 2012.2013. Our gas utility segment currently expects to invest approximately $1.0 billion$750 million to $800 million on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.
The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth.
Looking forward, we will focus on several areas that we expect will improve future performance:
| • | continuing to pursue regulatory stability and investment recovery for our utilities; | ||
| • | managing the growth of our utility asset base; | ||
| • | enhancing our cost structure across all business segments; | ||
| • | managing cash, capital and liquidity to maintain or improve our financial strength; | ||
| • | improving | ||
| • | investing in businesses that integrate our assets and leverage our skills and expertise. |
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We performed an assessment duringwill continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.
RESULTS OF OPERATIONS
Segments realigned —Beginning in the fourthsecond quarter of 20072008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment (now the Gas Midstream segment) to determine the impact, if any,Power and Industrial Projects segment due to changes in how financial information is evaluated and resources allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. See Note 20 of the current conditionsNotes to Consolidated Financial Statements in the credit marketsItem 8 of this Report for further information on our operations. We believe that our access to financing at reasonable interest rates, the fair value of assets held in trust to satisfy future obligations under our pension plans, and our counterparties’ creditworthiness will not be significantly affected by current conditions in the credit market.
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| (in Millions) | 2007 | 2006 | 2005 | |||||||||
Net Income by Segment: | ||||||||||||
| Electric Utility | $ | 317 | $ | 325 | $ | 277 | ||||||
| Gas Utility | 70 | 50 | 37 | |||||||||
| Non-utility Operations: | ||||||||||||
| Coal and Gas Midstream | 53 | 50 | 45 | |||||||||
| Unconventional Gas Production (1) | (217 | ) | 9 | 4 | ||||||||
| Power and Industrial Projects | 30 | (80 | ) | 4 | ||||||||
| Energy Trading | 32 | 96 | (43 | ) | ||||||||
| Corporate & Other (1) | 502 | (61 | ) | (52 | ) | |||||||
Income (Loss) from Continuing Operations: | ||||||||||||
| Utility | 387 | 375 | 314 | |||||||||
| Non-utility | (102 | ) | 75 | 10 | ||||||||
| Corporate & Other | 502 | (61 | ) | (52 | ) | |||||||
| 787 | 389 | 272 | ||||||||||
| Discontinued Operations | 184 | 43 | 268 | |||||||||
| Cumulative Effect of Accounting Changes | — | 1 | (3 | ) | ||||||||
| Net Income | $ | 971 | $ | 433 | $ | 537 | ||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
Net Income by Segment: | ||||||||||||
| Electric Utility | $ | 331 | $ | 317 | $ | 325 | ||||||
| Gas Utility | 85 | 70 | �� | 50 | ||||||||
| Non-utility Operations: | ||||||||||||
| Gas Midstream | 38 | 34 | 28 | |||||||||
| Unconventional Gas Production(1) | 84 | (217 | ) | 9 | ||||||||
| Power and Industrial Projects | 40 | 49 | (58 | ) | ||||||||
| Energy Trading | 42 | 32 | 96 | |||||||||
| Corporate & Other(1) | (94 | ) | 502 | (61 | ) | |||||||
Income (Loss) from Continuing Operations: | ||||||||||||
| Utility | 416 | 387 | 375 | |||||||||
| Non-utility | 204 | (102 | ) | 75 | ||||||||
| Corporate & Other | (94 | ) | 502 | (61 | ) | |||||||
| 526 | 787 | 389 | ||||||||||
| Discontinued Operations | 20 | 184 | 43 | |||||||||
| Cumulative Effect of Accounting Changes | — | — | 1 | |||||||||
| Net Income | $ | 546 | $ | 971 | $ | 433 | ||||||
| (1) |
ELECTRIC UTILITY
Our Electric Utility segment consists of Detroit Edison.
Factors impacting income:Our net Net income increased $14 million in 2008 and decreased $8 million in 20072007. The 2008 increase was primarily due to lower expenses for operation and increased $48 million in 2006.maintenance, depreciation and amortization, and taxes other than income, partly offset by lower gross margins and higher income tax expense. The 2007 decrease reflects higher operation and maintenance expenses, partially offset by higher gross margins and lower depreciation and amortization expenses.
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| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 4,874 | $ | 4,900 | $ | 4,737 | ||||||
| Fuel and Purchased Power | 1,778 | 1,686 | 1,566 | |||||||||
| Gross Margin | 3,096 | 3,214 | 3,171 | |||||||||
| Operation and Maintenance | 1,322 | 1,422 | 1,336 | |||||||||
| Depreciation and Amortization | 743 | 764 | 809 | |||||||||
| Taxes Other Than Income | 232 | 277 | 252 | |||||||||
| Asset (Gains) Losses and Reserves, Net | (1 | ) | 8 | (6 | ) | |||||||
| Operating Income | 800 | 743 | 780 | |||||||||
| Other (Income) and Deductions | 283 | 277 | 294 | |||||||||
| Income Tax Provision | 186 | 149 | 161 | |||||||||
| Net Income | $ | 331 | $ | 317 | $ | 325 | ||||||
| Operating Income as a Percent of Operating Revenues | 16 | % | 15 | % | 16 | % | ||||||
Gross margindecreased $118 million during 2008 and increased $43 million in 2007. The 2006 increase primarily reflects higher gross margins,2008 decrease was due to the unfavorable impacts of weather and service territory performance and the absence of the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation. These decreases were partially offset by increased depreciationhigher rates attributable to the April 2008 expiration of a rate reduction related to the MPSC show cause proceeding and amortization expenses.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Operating Revenues | $ | 4,900 | $ | 4,737 | $ | 4,462 | ||||||
| Fuel and Purchased Power | 1,686 | 1,566 | 1,590 | |||||||||
| Gross Margin | 3,214 | 3,171 | 2,872 | |||||||||
| Operation and Maintenance | 1,422 | 1,336 | 1,308 | |||||||||
| Depreciation and Amortization | 764 | 809 | 640 | |||||||||
| Taxes Other Than Income | 277 | 252 | 241 | |||||||||
| Asset (Gains) and Losses, Net | 8 | (6 | ) | (26 | ) | |||||||
| Operating Income | 743 | 780 | 709 | |||||||||
| Other (Income) and Deductions | 277 | 294 | 283 | |||||||||
| Income Tax Provision | 149 | 161 | 149 | |||||||||
| Net Income | $ | 317 | $ | 325 | $ | 277 | ||||||
| Operating Income as a Percent of Operating Revenues | 15 | % | 16 | % | 16 | % | ||||||
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reconciliation. The 2006 improvement was primarily due to increased rates due to the expiration of the residential rate cap on January 1, 2006 and returning sales from electric Customer Choice, partially offset by milder weather. Revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism.
The following table displays changes in various gross margin components relative to the comparable prior period:
| Increase (Decrease) in Gross Margin Components Compared to Prior Year | 2007 | 2006 | 2008 | 2007 | ||||||||||||
| (in Millions) | ||||||||||||||||
| Weather-related margin impacts | $ | 31 | $ | (81 | ) | |||||||||||
| Removal of residential rate caps effective January 1, 2006 | — | 186 | ||||||||||||||
| (In millions) | ||||||||||||||||
| Weather-related impacts | $ | (37 | ) | $ | 31 | |||||||||||
| Return of customers from electric Customer Choice | 43 | 156 | 35 | 43 | ||||||||||||
| Service territory economic performance | 28 | (16 | ) | |||||||||||||
| Service territory performance | (100 | ) | 28 | |||||||||||||
| Refundable pension cost | (30 | ) | — | |||||||||||||
| April 2008 expiration of show cause rate decrease | 46 | — | ||||||||||||||
| Impact of 2006 MPSC show cause order | (64 | ) | — | — | (64 | ) | ||||||||||
| Impact of 2005 MPSC PSCR reconciliation order | 38 | — | (38 | ) | 38 | |||||||||||
| Impact of 2004 MPSC PSCR reconciliation order | (39 | ) | 26 | — | (39 | ) | ||||||||||
| Other, net | 6 | 28 | 6 | 6 | ||||||||||||
| Increase in gross margin | $ | 43 | $ | 299 | ||||||||||||
| Increase (decrease) in gross margin | $ | (118 | ) | $ | 43 | |||||||||||
| 2007 | 2006 | 2005 | ||||||||||||||||||||||
Power Generated and Purchased (in Thousands of MWh) | ||||||||||||||||||||||||
| Power Plant Generation | ||||||||||||||||||||||||
| Fossil | 42,359 | 72 | % | 39,686 | 70 | % | 40,756 | 73 | % | |||||||||||||||
| Nuclear | 8,314 | 14 | 7,477 | 13 | 8,754 | 16 | ||||||||||||||||||
| 50,673 | 86 | 47,163 | 83 | 49,510 | 89 | |||||||||||||||||||
| Purchased Power | 8,422 | 14 | 9,861 | 17 | 6,378 | 11 | ||||||||||||||||||
| System Output | 59,095 | 100 | % | 57,024 | 100 | % | 55,888 | 100 | % | |||||||||||||||
| Less Line Loss and Internal Use | (3,391 | ) | (3,603 | ) | (3,205 | ) | ||||||||||||||||||
| Net System Output | 55,704 | 53,421 | 52,683 | |||||||||||||||||||||
Average Unit Cost ($/MWh) | ||||||||||||||||||||||||
| Generation (1) | $ | 15.83 | $ | 15.61 | $ | 15.47 | ||||||||||||||||||
| Purchased Power (2) | $ | 62.40 | $ | 53.71 | $ | 89.37 | ||||||||||||||||||
| Overall Average Unit Cost | $ | 22.47 | $ | 22.20 | $ | 23.90 | ||||||||||||||||||
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Power Generated and Purchased | 2008 | 2007 | 2006 | |||||||||||||||||||||
| (In thousands of MWh) | ||||||||||||||||||||||||
| Power Plant Generation | ||||||||||||||||||||||||
| Fossil | 41,254 | 71 | % | 42,359 | 72 | % | 39,686 | 70 | % | |||||||||||||||
| Nuclear | 9,613 | 17 | 8,314 | 14 | 7,477 | 13 | ||||||||||||||||||
| 50,867 | 88 | 50,673 | 86 | 47,163 | 83 | |||||||||||||||||||
| Purchased Power | 6,877 | 12 | 8,422 | 14 | 9,861 | 17 | ||||||||||||||||||
| System Output | 57,744 | 100 | % | 59,095 | 100 | % | 57,024 | 100 | % | |||||||||||||||
| Less Line Loss and Internal Use | (3,445 | ) | (3,391 | ) | (3,603 | ) | ||||||||||||||||||
| Net System Output | 54,299 | 55,704 | 53,421 | |||||||||||||||||||||
Average Unit Cost ($/MWh) | ||||||||||||||||||||||||
| Generation(1) | $ | 17.93 | $ | 15.83 | $ | 15.61 | ||||||||||||||||||
| Purchased Power | $ | 69.50 | $ | 62.40 | $ | 53.71 | ||||||||||||||||||
| Overall Average Unit Cost | $ | 24.07 | $ | 22.47 | $ | 22.20 | ||||||||||||||||||
| (1) | Represents fuel costs associated with power plants. | |
| (in Thousands of MWh) | 2007 | 2006 | 2005 | |||||||||
Electric Sales | ||||||||||||
| Residential | 16,147 | 15,769 | 16,812 | |||||||||
| Commercial | 19,332 | 17,948 | 15,618 | |||||||||
| Industrial | 13,338 | 13,235 | 12,317 | |||||||||
| Wholesale | 2,902 | 2,826 | 2,329 | |||||||||
| Other | 398 | 402 | 390 | |||||||||
| 52,117 | 50,180 | 47,466 | ||||||||||
| Interconnection sales (1) | 3,587 | 3,241 | 5,217 | |||||||||
| Total Electric Sales | 55,704 | 53,421 | 52,683 | |||||||||
Electric Deliveries | ||||||||||||
| Retail and Wholesale | 52,117 | 50,180 | 47,466 | |||||||||
| Electric Customer Choice | 1,690 | 2,694 | 6,760 | |||||||||
| Electric Customer Choice–Self Generators (2) | 549 | 909 | 518 | |||||||||
| Total Electric Sales and Deliveries | 54,356 | 53,783 | 54,744 | |||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In thousands of MWh) | ||||||||||||
Electric Sales | ||||||||||||
| Residential | 15,492 | 16,147 | 15,769 | |||||||||
| Commercial | 18,920 | 19,332 | 17,948 | |||||||||
| Industrial | 13,086 | 13,338 | 13,235 | |||||||||
| Wholesale | 2,825 | 2,902 | 2,826 | |||||||||
| Other | 393 | 398 | 402 | |||||||||
| 50,716 | 52,117 | 50,180 | ||||||||||
| Interconnection sales(1) | 3,583 | 3,587 | 3,241 | |||||||||
| Total Electric Sales | 54,299 | 55,704 | 53,421 | |||||||||
Electric Deliveries | ||||||||||||
| Retail and Wholesale | 50,716 | 52,117 | 50,180 | |||||||||
| Electric Customer Choice | 1,382 | 1,690 | 2,694 | |||||||||
| Electric Customer Choice — Self Generators(2) | 75 | 549 | 909 | |||||||||
| Total Electric Sales and Deliveries | 52,173 | 54,356 | 53,783 | |||||||||
| (1) | Represents power that is not distributed by Detroit Edison. | |
| (2) | Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements. |
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Operation and maintenanceexpense decreased $100 million in 2008 and increased $86 million in 20072007. The decrease in 2008 was due primarily to lower information systems implementation costs of $60 million, lower benefit expense of $45 million and $28lower corporate support expenses of $29 million, in 2006.partially offset by higher uncollectible expenses of $22 million. The increase in 2007 is primarily due to EBShigher information systems implementation costs of $30 million, higher storm expenses of $22 million, increased uncollectible expense of $22 million and higher corporate support expenses of $20 million. The 2006 increase was primarily due to increased distribution system maintenance of $35 million and increased plant outage costs of $33 million, partially offset by $36 million of lower storm expenses.
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Depreciation and amortizationexpense decreased $21 million in 2008 and $45 million in 2007 and increased $169 million in 2006.2007. The 2008 decrease was due primarily to decreased amortization of regulatory assets. The 2007 decrease was due primarily to a 2006 net stranded cost write-off of $112 million related to the September 2006 MPSC order regarding stranded costs and a $13 million decrease in our asset retirement obligation at our Fermi 1 nuclear facility, partially offset by $58 million of increased amortization of regulatory assets and $13 million of higher depreciation expense due to increased levels of depreciable plant assets. Amortization of prior year deferred CTA costs amounted to $10
Taxes other than incomedecreased $45 million in 2007. The 2006 increase was2008 due to a $112 million net stranded cost write-off related to the September 2006 MPSC order regarding stranded costs and a $19 million increaseMichigan Single Business Tax (SBT) expense in our asset retirement obligation at our Fermi 1 nuclear facility. In 2006, we also had increased amortization of regulatory assets of $19 million related to electric Customer Choice and $8 million related to our securitized assets.2007, which was replaced with the Michigan Business Tax (MBT) in 2008. The MBT is accounted for in the Income Tax provision.
Asset (gains) losses and losses,reserves, netgain decreased $9 million in 2008 and increased $14 million in 2007 due to a 2007 $13 million reserve for a loan guaranty related to Detroit Edison’s former ownership of a steam heating business now owned by Thermal Ventures II, LP (Thermal). The 2006 decrease resulted primarily from our 2005 sale of land near our headquarters in Detroit, Michigan.
Other (income) and deductionsexpense increased $6 million in 2008 and decreased $17 million in 20072007. The 2008 increase is attributable to $15 million of investment losses in a trust utilized for retirement benefits and increased $11$3 million in 2006.of miscellaneous expenses offset by higher capitalized interest of $12 million. The 2007 decrease is attributable to a $10 million contribution to the DTE Energy Foundation in 2006 that did not re-occurrecur in 2007, $3 million of higher interest income and $17 million of increased miscellaneous utility related services, partially offset by $16 million of higher interest expense. The 2006 increase is primarily attributable to higher interest expense due to increased long-term debt.
Outlook– — We will move forward in our efforts to continue to improve the operating performance and cash flow of Detroit Edison. We continue to resolve outstanding regulatory issues by pursuing regulatoryand/or legislative solutions. Many of these issues and continue to pursue additional regulatory and/or legislative solutions for structural problems withinhave been addressed by the legislation signed by the Governor of Michigan electric market structure, primarily electric Customer Choice andin October 2008, discussed more fully in the need to adjust rates for each customer class to reflect the full cost of service. We are also seeking regulatory reform to insure more timely cost recovery and resolution of rate cases.Overview section. Looking forward, additional issues, such as risingvolatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans, health care costs and higher levels of capital spending, will result in us taking meaningful action to address our costs while continuing to provide quality customer service. We will utilize the DTE Energy Operating System and the Performance Excellence Processcontinue to seek opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.
Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.
Due to the economy and credit market conditions, in the near term, we are reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust the timing of projects as appropriate. Long term, we will be required to invest an estimated $2.4$2.8 billion on emission controls through 2018. We intend to seek recovery of these investments in future rate cases.
Additionally, our service territory may require additional generation capacity. A new base-load generating plant has not been built within the State of Michigan in over 20 years. Should our economic and regulatory environment be conducive to such a significant capital expenditure, we may build, upgrade or co-invest in a base-load coal facility or a new nuclear plant. While we
On September 18, 2008, Detroit Edison submitted a Combined Operating License Application with the NRC for construction and operation of a possible 1,500 MW nuclear power plant at the site of the company’s existing Fermi 2 nuclear plant. We have not decided on construction of a new base-load nuclear plant, in February 2007, we announced that we will prepare a license application for construction and operation of a new nuclear power plant on the site of Fermi 2. Byplant; however, by completing the license application before the end of 2008, we may qualify for financial incentives under the Federal Energy Policy Act of 2005. We areIn addition, Detroit Edison is also studying the possible transfer of a gas-fired peaking electric generating plant from our non-utility operations to our electric utility to support future power generation requirements.moving ahead with plans for renewable energy resources and an aggressive energy efficiency program.
The following variables, either individually or in combination, or acting alone, could impact our future results:
| • | Access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings; |
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| • | Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on cash equivalents and investments; | ||
| • | Economic conditions within Michigan and corresponding impacts on demand for electricity; | ||
| • | Collectibility of accounts receivable; | ||
| • | Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions; | ||
| • | The amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation; | ||
| • | |||
| • | |||
| • | |||
| • | |||
| • | Any potential new federal and state environmental, renewable energy and energy efficiency requirements. |
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GAS UTILITY
Our Gas Utility segment consists of MichCon and Citizens.
Factors impacting income:Gas Utility’s net income increased $15 million in 2008 and $20 million in 20072007. The 2008 and $13 million in 2006. The 2007 and 2006 increases were due primarily to higher gross margins.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Operating Revenues | $ | 1,875 | $ | 1,849 | $ | 2,138 | $ | 2,152 | $ | 1,875 | $ | 1,849 | ||||||||||||
| Cost of Gas | 1,164 | 1,157 | 1,490 | 1,378 | 1,164 | 1,157 | ||||||||||||||||||
| Gross Margin | 711 | 692 | 648 | 774 | 711 | 692 | ||||||||||||||||||
| Operation and Maintenance | 429 | 431 | 424 | 464 | 429 | 431 | ||||||||||||||||||
| Depreciation and Amortization | 93 | 94 | 95 | 102 | 93 | 94 | ||||||||||||||||||
| Taxes Other Than Income | 56 | 53 | 43 | 48 | 56 | 53 | ||||||||||||||||||
| Asset (Gains) and Losses, Net | (3 | ) | — | 4 | (26 | ) | (3 | ) | — | |||||||||||||||
| Operating Income | 136 | 114 | 82 | 186 | 136 | 114 | ||||||||||||||||||
| Other (Income) and Deductions | 43 | 53 | 47 | 60 | 43 | 53 | ||||||||||||||||||
| Income Tax Provision (Benefit) | 23 | 11 | (2 | ) | 41 | 23 | 11 | |||||||||||||||||
| Net Income | $ | 70 | $ | 50 | $ | 37 | $ | 85 | $ | 70 | $ | 50 | ||||||||||||
| Operating Income as a Percent of Operating Revenues | 7 | % | 6 | % | 4 | % | 9 | % | 7 | % | 6 | % | ||||||||||||
Gross marginincreased $63 million and $19 million in 2008 and $442007, respectively. The increase in 2008 reflects $49 million infrom the uncollectible tracking mechanism, $15 million related to the impacts of colder weather, $10 million favorable result of lower lost gas recognized and higher valued gas received as compensation for transportation of third party customer gas, $7 million of 2007 GCR disallowances, and 2006, respectively.$6 million of appliance repair revenue. The 2008 improvement was partially offset by $19 million of lower storage services revenue and $12 million from customer conservation and lower volumes. The increase in 2007 is primarily due to $21 million from the favorable effects of weather in 2007 and $28 million related to an increase in midstream services including storage and transportation, partially offset by a $26 million unfavorable impact in lost gas recognized and $7 million in GCR disallowances. The increase in 2006 is primarily due to $15 million in higher base rates and $22 million in higher revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC in the April 2005 gas rate order. Additionally, 2006 was impacted by a $17 million favorable impact in lost gas recognized and an increase of $24 million in midstream services including storage and transportation. Partially offsetting these increases were declines of $31 million due to warmer than normal weather and $26 million as a result of customer conservation and lower volumes. The comparability of 2006 to 2005 is also affected by an adjustment we recorded in the first quarter of 2005 related to an April 2005 MPSC order in our 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at December 31, 2001. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.mechanism.
| 2007 | 2006 | 2005 | ||||||||||
Gas Markets (in Millions) | ||||||||||||
| Gas sales | $ | 1,536 | $ | 1,541 | $ | 1,860 | ||||||
| End user transportation | 140 | 135 | 134 | |||||||||
| 1,676 | 1,676 | 1,994 | ||||||||||
| Intermediate transportation | 59 | 69 | 58 | |||||||||
| Storage and other | 140 | 104 | 86 | |||||||||
| $ | 1,875 | $ | 1,849 | $ | 2,138 | |||||||
Gas Markets (in Bcf) | ||||||||||||
| Gas sales | 148 | 138 | 168 | |||||||||
| End user transportation | 132 | 136 | 157 | |||||||||
| 280 | 274 | 325 | ||||||||||
| Intermediate transportation | 399 | 373 | 432 | |||||||||
| 679 | 647 | 757 | ||||||||||
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| 2008 | 2007 | 2006 | ||||||||||
Gas Markets (in Millions) | ||||||||||||
| Gas sales | $ | 1,824 | $ | 1,536 | $ | 1,541 | ||||||
| End user transportation | 143 | 140 | 135 | |||||||||
| 1,967 | 1,676 | 1,676 | ||||||||||
| Intermediate transportation | 73 | 70 | 69 | |||||||||
| Storage and other | 112 | 129 | 104 | |||||||||
| $ | 2,152 | $ | 1,875 | $ | 1,849 | |||||||
Gas Markets (in Bcf) | ||||||||||||
| Gas sales | 148 | 148 | 138 | |||||||||
| End user transportation | 123 | 132 | 136 | |||||||||
| 271 | 280 | 274 | ||||||||||
| Intermediate transportation | 438 | 399 | 373 | |||||||||
| 709 | 679 | 647 | ||||||||||
Operation and maintenanceexpense increased $35 million in 2008 and decreased $2 million in 20072007. The 2008 increase is primarily attributable to $56 million of higher uncollectible expenses, partially offset by $14 million of lower corporate support expenses and $14 million of reduced pension and retiree health benefit costs. The increase in uncollectible expense is partially offset by increased $7 millionrevenues from the uncollectible tracking mechanism included in 2006.the gross margin discussion. The 2007 decrease was attributed to $4 million of lower uncollectible expense and $4 million of reduced corporate support expenses, partially offset by $5 million in increased EBSinformation systems implementation costs. The 2006 increase is due to $14 million of higher uncollectible expense and $24
Other Asset (gains) losses, netincreased $23 million in implementation
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Outlook —– Operating results are expected to vary due to regulatory proceedings, weather, changes in economic conditions, customer conservation, process improvements and base gas sales. Higher gas prices and deteriorating economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s uncollectible true-up mechanismGCR and GCR mechanism.
uncollectibletrue-up mechanisms. We will continue to utilize the DTE Energy Operating System and the Performance Excellence Process to seek opportunities to improve productivity, minimize lost gas, remove waste and decrease our costs while improving customer satisfaction.
Unfavorable national and regional economic trends have resulted in negative customer growth in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.
The following variables, either individually or in combination, could impact our future results:
| • | Access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings; | |
| • | Instability in capital markets which could impact availability of short and long-term financing or the potential for loss on cash equivalents and investments; | |
| • | Economic conditions within Michigan and corresponding impacts on demand for gas and levels of lost or stolen gas; | |
| • | Collectibility of accounts receivable; | |
| • | Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions; | |
| • | The amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation; |
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| • | Our ability to reduce costs and maximize distribution system performance; | |
| • | Variations in market prices of gas; | |
| • | Weather; | |
| • | Customer conservation; | |
| • | Volatility in the short-term storage markets which impact third-party storage revenues; | |
| • | Extent and timing of any base gas sales; | |
| • | Any potential new federal and state environmental, renewable energy and energy efficiency requirements. |
NON-UTILITY OPERATIONS
Our Coal and Gas Midstream segment consists of Coal Transportationour non-utility gas pipelines and Marketing and the Pipelines, Processing and Storagestorage businesses.
Factors impacting incomeincome:: Net income increased $3$4 million and $5$6 million in 2008 and 2007, respectively. The 2008 increase is due to higher storage revenues related to expansion of capacity and 2006, respectively.higher other income primarily driven by higher equity earnings from our investments in the Vector and Millennium Pipelines, partially offset by a higher tax provision due to the MBT in 2008. Net income was higher in 2007 due to higher midstream gas storage revenues offset by increased overhead related to legal expenses.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Operating Revenues | $ | 837 | $ | 707 | $ | 707 | ||||||
| Operation and Maintenance | 747 | 628 | 653 | |||||||||
| Depreciation and Amortization | 8 | 4 | 3 | |||||||||
| Taxes Other Than Income | 5 | 5 | 4 | |||||||||
| Asset (Gains) and Losses, Net | (1 | ) | — | — | ||||||||
| Operating Income | 78 | 70 | 47 | |||||||||
| Other (Income) and Deductions | (5 | ) | (8 | ) | (20 | ) | ||||||
| Income Tax Provision | 30 | 28 | 22 | |||||||||
| Net Income | $ | 53 | $ | 50 | $ | 45 | ||||||
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| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 71 | $ | 66 | $ | 63 | ||||||
| Operation and Maintenance | 12 | 13 | 22 | |||||||||
| Depreciation and Amortization | 5 | 6 | 3 | |||||||||
| Taxes Other Than Income | 3 | 3 | 4 | |||||||||
| Asset (Gains) and Losses, Net | 1 | (1 | ) | (1 | ) | |||||||
| Operating Income | 50 | 45 | 35 | |||||||||
| Other (Income) and Deductions | (12 | ) | (7 | ) | (8 | ) | ||||||
| Income Tax Provision | 24 | 18 | 15 | |||||||||
| Net Income | $ | 38 | $ | 34 | $ | 28 | ||||||
Outlook– In 2008, we expect to see a decrease in net income since approximately $11 million of our 2007 Coal Transportation and Marketing net income was dependent upon our Synfuel operations that ceased operations at the end of 2007. Beyond 2008, we expect to continue to grow our Coal Transportation and Marketing business in a manner consistent with, and complementary to, the growth of our other business segments.
— Our Pipelines, Processing and StorageGas Midstream business expects to continue its steady growth plan. In April 2007, Washington 28 received MPSC approval to increase working gas2008, an additional 7 Bcf of storage capacity by over 6 Bcfwas placed in service. Future additions to a total of 16 Bcf by April 2008. In June 2007, Washington 10 received MPSC approval to develop the Shelby 2 storage field which will increase the working gas storage capacity of Washington 10approximately 3 Bcf will occur over the next two years by 8 Bcf to a total of 74 Bcf.few months. Vector Pipeline placed into service its Phase 1 expansion for approximately200 MMcf/d in November 2007. This project is fully supported by customers with long-term agreements. In addition, Vector Pipeline requested permission from thereceived FERC approval in the fourth quarter of 2007June 2008 to build one moreadditional compressor station, and towhich will expand the Vector Pipeline by approximately100 MMcf/d, with a proposed in-service date of November 1, 2009. Adding another compressor station will bring the system from its current capacity of about 1.2 Bcf/d up to 1.3 Bcf/d in 2009. Pipelines, ProcessingBoth the 2007 and Storage has a 26 percent ownership interest in2009 expansion projects are supported by customers under long-term contracts. Millennium Pipeline which commenced construction in June 2007 and is scheduled to bewas placed in service in late 2008. We planDecember 2008 and currently has nearly 85% of its capacity sold to expand existing assets and develop new assets which are typically supported withcustomers under long-term customer commitments.contracts.
Unconventional Gas Production
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production primarily within the Barnett shale in northnorthern Texas. OnIn June 29, 2007, we sold our Antrim shale gas exploration and production business in the northern lower peninsula of Michigan for gross proceeds of $1.262 billion.
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In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The gainproperties sold included 75 Bcf of proved reserves on sale is includedapproximately 11,000 net acres in the Corporate & Other segment. See Note 3core area of the Notes to Consolidated Financial StatementsBarnett shale. We recognized a gain of $128 million ($81 million after-tax) on the sale in Item 8 of this Report.2008.
Factors impacting incomeincome:: Net income decreased $226 million The 2008 results include the gain recognized on the sale of our Barnett shale property described above. In addition, lower gas sales volumes were offset by higher commodity prices and higher gas and oil production from retained wells in 2008 compared to 2007. The 2007 and increased $5 million in 2006. The significant decline in results in 2007 reflectsreflect the recording of $323 million of losses on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales and impairments of our southern expansion area of the Barnett shale in 2007. The 2006 results were primarily impacted by an increase in Barnett shale production and an increase in net gas prices for Antrim shale. Partially offsetting these revenue increases were higher operating and depletion expenses associated with increased production and the operation of new wells.through 2013.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Operating Revenues | $ | (228 | ) | $ | 99 | $ | 74 | |||||
| Operation and Maintenance | 36 | 37 | 30 | |||||||||
| Depreciation, Depletion and Amortization | 22 | 27 | 20 | |||||||||
| Taxes Other Than Income | 8 | 11 | 11 | |||||||||
| Asset (Gains) and Losses, Net | 27 | (3 | ) | — | ||||||||
| Operating Income (Loss) | (321 | ) | 27 | 13 | ||||||||
| Other (Income) and Deductions | 13 | 13 | 8 | |||||||||
| Income Tax Provision (Benefit) | (117 | ) | 5 | 1 | ||||||||
| Net Income (Loss) | $ | (217 | ) | $ | 9 | $ | 4 | |||||
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| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 48 | $ | (228 | ) | $ | 99 | |||||
| Operation and Maintenance | 22 | 36 | 37 | |||||||||
| Depreciation, Depletion and Amortization | 12 | 22 | 27 | |||||||||
| Taxes Other Than Income | 1 | 8 | 11 | |||||||||
| Asset (Gains) and Losses, Net | (120 | ) | 27 | (3 | ) | |||||||
| Operating Income (Loss) | 133 | (321 | ) | 27 | ||||||||
| Other (Income) and Deductions | 2 | 13 | 13 | |||||||||
| Income Tax Provision (Benefit) | 47 | (117 | ) | 5 | ||||||||
| Net Income (Loss) | $ | 84 | $ | (217 | ) | $ | 9 | |||||
Operating revenuesincreased $276 million in 2008 and decreased $327 million in 2007. The 2007 decrease for 2007 was due toreflects the recording of $323 million of losses during 2007 on financial contracts that hedged our price risk exposure related to expected Antrim gas production and sales through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions. As a result of these transactions and market research performed by the Company, we gained additional insight and visibility into the value ascribed to these contracts by third party market participants for the duration of the contracts. In conjunction with the Antrim sale, and effective settlement of these contract positions, Antrim reclassified amounts held in Accumulatedaccumulated other comprehensive income, and recorded the effective settlements, reducing operating revenues in the 2007 period by $323 million. OperatingExcluding the impact of the losses on the Antrim hedges, operating revenues increased $25decreased $47 million in 20062008 as compared to 2007. The decreases were principally due to lower natural gas sales volumes as a result of our monetization initiatives, partially offset by higher commodity prices and higher gas and oil production on retained wells.
Other assets (gains) losses, netincreased $147 million in 2008 due to the gain on sale of Barnett shale production.
Outlook —– On January 15, 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $250 million, subject to post-closing adjustments. We will recognize a gain on the sale in the first quarter of 2008. The properties in the sale included 186 billion cubic feet of proved and probable reserves on approximately 11,000 net acres in the core area of the Barnett shale.
We plan to retaincontinue to develop our holdings in the western portion of the Barnett shale and anticipate significantto seek opportunities to developfor additional monetization of select properties within our current position while accumulating additional acreage in and around our existing assets.
appropriate. We invested approximately $140$96 million in the Barnett shale in 2007.2008. During 2007,2009, we expect to invest approximately $25 million to drill 15 to 25 new wells and achieve Barnett shale production wasof approximately 7.75 to 6 Bcfe of natural gas from our remaining properties, compared with approximately 4.15 Bcfe in 2006.2008.
Power and Industrial Projects
Power and Industrial Projects segment is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers,customers; provide coal transportation services and biomassmarketing; and sell electricity from biomass-fired energy projects.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Operating Revenues | $ | 473 | $ | 409 | $ | 428 | ||||||
| Operation and Maintenance | 409 | 366 | 329 | |||||||||
| Depreciation and Amortization | 39 | 48 | 48 | |||||||||
| Taxes other than Income | 11 | 12 | 14 | |||||||||
| Asset (Gains) and Losses, Reserves and Impairments, Net | — | 75 | (1 | ) | ||||||||
| Operating Income (Loss) | 14 | (92 | ) | 38 | ||||||||
| Other (Income) and Deductions | (13 | ) | 43 | 4 | ||||||||
| Minority Interest | 2 | 1 | 37 | |||||||||
| Income Taxes | ||||||||||||
| Provision (Benefit) | 6 | (44 | ) | 5 | ||||||||
| Production Tax Credits | (11 | ) | (12 | ) | (12 | ) | ||||||
| (5 | ) | (56 | ) | (7 | ) | |||||||
| Net Income (Loss) | $ | 30 | $ | (80 | ) | $ | 4 | |||||
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During the third quarter of 2007, we announced plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second quarter of 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, our work on this planned monetization was discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used.
Factors impacting income: Net income decreased $9 million in 2008 and increased $107 million in 2007.
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 987 | $ | 1,244 | $ | 1,053 | ||||||
| Operation and Maintenance | 899 | 1,143 | 972 | |||||||||
| Depreciation and Amortization | 34 | 41 | 49 | |||||||||
| Taxes other than Income | 12 | 13 | 13 | |||||||||
| Other Asset (Gains) and Losses, Reserves and Impairments, Net | 6 | — | 76 | |||||||||
| Operating Income (Loss) | 36 | 47 | (57 | ) | ||||||||
| Other (Income) and Deductions | (20 | ) | (11 | ) | 43 | |||||||
| Minority Interest | 5 | 2 | 1 | |||||||||
| Income Taxes | ||||||||||||
| Provision (Benefit) | 18 | 18 | (31 | ) | ||||||||
| Production Tax Credits | (7 | ) | (11 | ) | (12 | ) | ||||||
| 11 | 7 | (43 | ) | |||||||||
| Net Income (Loss) | $ | 40 | $ | 49 | $ | (58 | ) | |||||
Operating revenuesincreased $64decreased $257 million in 2008. This was primarily attributable to $177 million of reductions in coal transportation and trading volumes and $28 million for the impact of a customer electing to purchase coal directly from the supplier. Revenues in 2007 increased $191 million reflecting a new long-term utility services contract with a large automotive company, higher coke prices and sales volumes in addition to higher volumes at several other projects. Additionally, revenue was earned for a one-time success fee from the sale of an asset we operated for a third party. RevenuesIn 2007, revenues were impacted by higher synfuel related volumes and increases in 2006 decreased $19 million due primarilytrading volumes related to lower coke pricesboth coal and lower pulverized coal sales. The 2006 decrease was partially offset by increased revenue from our on-site energy projects, reflecting the addition of new facilities, completion of new long-term utility services contracts with a large automotive company and a large manufacturer of paper products.emissions.
Operation and maintenanceexpense increased $43decreased $244 million in 20072008 and $37increased $171 million in 2006.2007. The increases resulted from2008 decrease mostly reflects $174 million of lower coal transportation costs driven by reduced sales combined with a reduction in coal trading results. The 2007 increase was due to higher costssynfuel related production and higher trading volumes related to the addition of new facilities, a new long-term utility services contract with a large automotive companycoal and higher volumes at several other projects.emissions.
Depreciation and amortizationexpense decreased $9$7 million in 2008 and $8 million in 2007 due primarily to the suspension of $6 million of depreciation expense in the fourth quarter of 2007 related to the assets held for sale, the sale of a generation facility during the year and reduced depreciation expense as a result of asset impairments at several biomass landfill sites in 2006.
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Other (income) and deductionsexpense decreased $56were higher by $9 million in 2008 due primarily to higher inter-company interest. The 2007 and increased $39 million in 2006decrease was due primarily due to a realized gain of $8 million on the sale of a 50 percent equity interest in a natural gas-fired generating plant and a $4 million gain recognized in 2007 on an installment sale of a coke battery facility, a reduction of $5 million in interest expense and a $32 million impairment of a 51% equity interest in a natural gas-fired generating plant in 2006.facility.
Outlook– — The deterioration in the U.S. economy is expected to continue to negatively impact our customers in the steel industry and we expect a corresponding reduction in demand for metallurgical coke and pulverized coal supplied to these customers in 2009. We expect to sell a 50 percent interest in a portfolio of select Power and Industrial Projects. In additionsupply onsite energy services to the proceeds thatdomestic automotive manufacturers who have also been negatively affected by the Companyeconomic downturn and constriction in the capital and credit markets. Our onsite energy services are delivered in accordance with the terms of long-term contracts which include termination payments in the event of plant closures or other events of default and have not been significantly impacted by the financial distress experienced by the automotive manufacturers. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on the results of our onsite energy projects. We continue to monitor developments in this sector. In 2009, we expect our coal transportation and marketing business to positively contribute to the results of this segment as our coal transportation, storage and blending services continue to grow. In 2011, our existing long-term rail transportation contract which gives us a competitive advantage will receive from the sale of the 50 percent equity interest, the company thatexpire. We will own the Projects will obtain debt financingcontinue to work with suppliers and the proceeds will be distributedrailroads to DTE Energy immediately priorpromote secure and competitive access to coal to meet the saleenergy requirements of the equity interest. The total gross proceeds the Company will receive are expected to approximate $650 million. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completion of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operations of the Projects and to act as the managing member of the company that owns the Projects. We plan to account for our 50 percent ownership interest in the company that will own the portfolio of projects using the equity method. See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.customers.
Power and Industrial Projects will continue leveragingto leverage its extensive energy-related operating experience and project management capability to develop additionalon-site energy projects to serve energy intensive industrial customers that are experiencing capital constraints due to the economic downturn. We will also continue to look for opportunities to acquireon-site energy projects and grow the on-site energy business.biomass fired generating projects for advantageous prices.
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Energy Trading
Our Energy Trading segment focuses on physical power and gas marketing, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, optimization of contracted natural gas pipelinespipeline transportation and storage, and power transmission and generating capacity positions.
Factors impacting incomeincome:: Net income increased $10 million in 2008 and decreased $64 million in 2007 and 2007.
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 1,388 | $ | 924 | $ | 828 | ||||||
| Fuel, Purchased Power and Gas | 1,235 | 806 | 607 | |||||||||
| Gross Margin | 153 | 118 | 221 | |||||||||
| Operation and Maintenance | 68 | 58 | 65 | |||||||||
| Depreciation and Amortization | 5 | 5 | 6 | |||||||||
| Taxes Other Than Income | 2 | 1 | 1 | |||||||||
| Operating Income (Loss) | 78 | 54 | 149 | |||||||||
| Other (Income) and Deductions | 5 | 5 | 4 | |||||||||
| Income Tax Provision (Benefit) | 31 | 17 | 49 | |||||||||
| Net Income (Loss) | $ | 42 | $ | 32 | $ | 96 | ||||||
Gross marginincreased $139$35 million in 2006.2008 and decreased $103 million in 2007. The 2008 increase is due to higher unrealized margin of $66 million offset by a decrease in realized margin of $31 million. The increase in unrealized margins includes $18 million in improved gains in the gas trading strategy, $26 million gains on economic hedges of storage positions due to falling gas prices, and the absence of $30 million in mark-to-market losses in June 2007 reflecting revisions of valuation estimates for natural gas contracts, offset by $10 million in losses on economic hedges in our gas transportation strategy. The decrease in 2007 was attributablerealized
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margin is due to lower gross marginsunfavorability of $28 million primarily from our power marketing and an increasetransmission optimization strategies, $34 million of unfavorability in other deductions. The 2006 increase is attributed to increased mark-to-market and realized power and gas positions that resulted from significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Operating Revenues | $ | 955 | $ | 830 | $ | 977 | ||||||
| Fuel, Purchased Power and Gas | 807 | 616 | 984 | |||||||||
| Gross Margin | 148 | 214 | (7 | ) | ||||||||
| Operation and Maintenance | 58 | 65 | 43 | |||||||||
| Depreciation and Amortization | 5 | 6 | 4 | |||||||||
| Taxes Other Than Income | 1 | 1 | (1 | ) | ||||||||
| Operating Income (Loss) | 84 | 142 | (53 | ) | ||||||||
| Other (Income) and Deductions | 35 | (3 | ) | 13 | ||||||||
| Income Tax Provision (Benefit) | 17 | 49 | (23 | ) | ||||||||
| Net Income (Loss) | $ | 32 | $ | 96 | $ | (43 | ) | |||||
Operation and maintenanceexpense increased $10 million in 2008 and decreased $7 million in 20072007. The 2008 increase is due to higher payroll and increased $22 million in 2006.incentive costs and allocated corporate costs. The 2007 decrease was due primarily to lower incentive expenses of $7 million. The 2006 increase was due to higher incentive expenses of $14 million resulting from our strong economic performance and higher corporate allocation charges of $10 million.expenses.
Outlook- — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as capacity positions ofcontracted natural gas pipeline transportation and storage, natural gas pipelines, and power transmission and full requirements contracts. Thegeneration capacity positions. Most financial instruments are deemed derivatives, whereas the ownedproprietary gas inventory, pipelines,power transmission, contracts,pipeline transportation and certain full requirements contracts and storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. The majorityA source of such earnings volatility is associated with the natural gas storage cycle, which does not coincide with the calendar year, but runs annually from April of one year to March of the next year. Our strategy is to economically manage the price risk of storage with futures, and over-the-counter forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.
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See “FairCapital Resources and Liquidity and Fair Value sections that follow for additional discussion of Contracts” section that follows.our trading activities.
CORPORATE & OTHER
Corporate & Other includes various corporate staff functions. As these functions support the entire Company, their costs are fully allocated to the various segments based on services utilized. Therefore, the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Otherholding company activities and holds certain non-utility debt and energy-related investments.
Factors impacting incomeincome:: Corporate & Other results decreased by $597 million in 2008 and increased by $563 million in 2007, which2007. This is primarilymostly attributable to the 2007 gain on the sale of the Antrim shale gas exploration and production business offor approximately $900 million ($580 million after-tax). Corporate & Other results declined by $9 million and variations in 2006, primarily due to higher Michigan Single Business Taxes.inter-company interest.
DISCONTINUED OPERATIONS
Synthetic Fuel
The Company discontinued the operations of our synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel business generated operating losses that were offset by production tax credits.
Factors impacting incomeincome:: Synthetic Fuel net income decreased $185 million in 2008 and increased $157 million in 2007. The decrease in 2008 was due to the cessation of operations of our synfuel facilities at December 31, 2007 and decreased $257 millionthe final determination of the 2007 IRS reference price and inflation factor in 2006.2008. The increase in 2007 was due to synfuel production occurring throughout the year in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006 and higher income from oil price hedges, partially offset by a higher phase-out of production tax credits due to high oil prices. The decline in 2006 was also due to higher oil prices resulting in reduced gains from selling interests in our synfuel plants, lower levels of production tax credits and asset impairments and reserves.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Operating Revenues | $ | 1,069 | $ | 863 | $ | 927 | ||||||
| Operation and Maintenance | 1,265 | 1,019 | 1,167 | |||||||||
| Depreciation and Amortization | (6 | ) | 24 | 58 | ||||||||
| Taxes other than Income | 5 | 12 | 20 | |||||||||
| Asset (Gains) and Losses, Reserves and Impairments, Net (1) | (280 | ) | 40 | (367 | ) | |||||||
| Operating Income (Loss) | 85 | (232 | ) | 49 | ||||||||
| Other (Income) and Deductions | (9 | ) | (20 | ) | (34 | ) | ||||||
| Minority Interest | (188 | ) | (251 | ) | (318 | ) | ||||||
| Income Taxes | ||||||||||||
| Provision (Benefit) | 98 | 14 | 139 | |||||||||
| Production Tax Credits | (21 | ) | (23 | ) | (43 | ) | ||||||
| 77 | (9 | ) | 96 | |||||||||
| Net Income (1) | $ | 205 | $ | 48 | $ | 305 | ||||||
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| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Operating Revenues | $ | 7 | $ | 1,069 | $ | 863 | ||||||
| Operation and Maintenance | 9 | 1,265 | 1,019 | |||||||||
| Depreciation and Amortization | (2 | ) | (6 | ) | 24 | |||||||
| Taxes other than Income | (1 | ) | 5 | 12 | ||||||||
| Asset (Gains) and Losses, Reserves and Impairments, Net(1) | (31 | ) | (280 | ) | 40 | |||||||
| Operating Income (Loss) | 32 | 85 | (232 | ) | ||||||||
| Other (Income) and Deductions | (2 | ) | (9 | ) | (20 | ) | ||||||
| Minority Interest | 2 | (188 | ) | (251 | ) | |||||||
| Income Taxes | ||||||||||||
| Provision (Benefit) | 13 | 98 | 14 | |||||||||
| Production Tax Credits | (1 | ) | (21 | ) | (23 | ) | ||||||
| 12 | 77 | (9 | ) | |||||||||
| Net Income(1) | $ | 20 | $ | 205 | $ | 48 | ||||||
| (1) | Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007. |
Operating revenuesdecreased $1,062 million in 2008 and increased $206 million in 2007. The 2008 drop is due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2008 activity reflects the increased value of 2007 synfuel production as a result of final determination of the IRS Reference Price and inflation factor. Synfuel production was higher in 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.
Operation and maintenanceexpense decreased $64$1,256 million in 20062008 and increased $246 million in 2007. The 2008 reduction is due to the cessation of operations of our synfuel facilities at December 31, 2007. Activity for 2008 reflects adjustments to 2007 contractually defined cost sharing mechanisms with suppliers, as determined by applying the actual phase-out percentage. The 2007 increase reflects synfuel production occurring throughout 2007 in comparison to 2006 when production was idled at all nine of our synfuel facilities from May to October 2006.
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Depreciation and amortizationexpense was lower by $30 million in 2007 and $34 million in 2006 as a result of reductions in asset retirement obligations in 2007 and the impairment of fixed assets at all nine synfuel projects in 2006.
Asset (gains) and losses, reserves and impairments, netgaindecreased $249 million in 2008 and increased $320 million in 2007. The 2008 decrease was due to the cessation of operations of our synfuel facilities at December 31, 2007 and decreased $407 million in 2006. reflects the impact of reserve adjustments for the final phase-out percentage andtrue-ups of final payments and distributions to partners.
The increase in gains in 2007 reflects the annual partner payment adjustment, recognition of certain fixed gains that were reserved during the comparable 2006 period, higher hedge gains and the impact of one-time impairment charges and fixed note reserves recorded in 2006. In 2007 and 2006, we deferred gains from the sale of the synfuel facilities, including a portion of gains related to fixed payments. Due to the increase in oil prices, we recorded accruals for contractual partners’ obligations of $130 million in 2007 and $79 million in 2006 reflecting the probable refund of amounts equal to our partners’ capital contributions or for operating losses that would normally be paid by our partners. In 2007, we reversed $3 million of other synfuel-related reserves and impairments and in 2006 recorded $78 million of other synfuel-related reserves and impairments. To economically hedge our exposure to the risk of an increase in oil prices and the resulting reduction in synfuel sales proceeds, we entered into derivative and other contracts. The derivative contracts are marked-to-market with changes in their fair value recorded as an adjustment to synfuel gains. We recorded net 2007 synfuel hedge mark-to-market gains of $196 million compared with net 2006 synfuel hedge mark-to-market gains of $60 million. See Note 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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The following table displays the various pre-tax components that comprise the determination of synfuel gains and losses in 2008, 2007 2006 and 2005.2006.
| (in Millions) | ||||||||||||
| Components of Asset (Gains) Losses, Reserves and | ||||||||||||
| Impairments, Net | 2007 | 2006 | 2005 | |||||||||
| Gains recognized associated with fixed payments | $ | (172 | ) | $ | (43 | ) | $ | (132 | ) | |||
| Gains recognized associated with variable payments | (39 | ) | (14 | ) | (187 | ) | ||||||
| Reserves recorded for contractual partners’ obligations | 130 | 79 | — | |||||||||
| Other reserves and impairments, including partners’ share (1) | (3 | ) | 78 | — | ||||||||
| Hedge (gains) losses: | ||||||||||||
| Hedges for 2005 exposure | — | — | (2 | ) | ||||||||
| Hedges for 2006 exposure | — | (66 | ) | (40 | ) | |||||||
| Hedges for 2007 exposure | (196 | ) | 6 | (6 | ) | |||||||
| $ | (280 | ) | $ | 40 | $ | (367 | ) | |||||
| Components of Asset (Gains) Losses, Reserves and | ||||||||||||
Impairments, Net | 2008 | 2007 | 2006 | |||||||||
| (In millions) | ||||||||||||
| Gains recognized associated with fixed payments | $ | — | $ | (172 | ) | $ | (43 | ) | ||||
| Gains recognized associated with variable payments | (32 | ) | (39 | ) | (14 | ) | ||||||
| Reserves recorded for contractual partners’ obligations | — | 130 | 79 | |||||||||
| Other reserves and impairments, including partners’ share(1) | (1 | ) | (3 | ) | 78 | |||||||
| Hedge (gains) losses: | ||||||||||||
| Hedges for 2006 exposure | — | — | (66 | ) | ||||||||
| Hedges for 2007 exposure | (196 | ) | 6 | |||||||||
| $ | (33 | ) | $ | (280 | ) | $ | 40 | |||||
| (1) | Includes $70 million in 2006, representing our partners’ share of the asset impairment, included in Minority Interest. |
Minority interestdecreased by $190 million and $63 million in 2008 and $67 million in 2007, and 2006, respectively. The amounts reflect2008 reduction is due to the cessation of operations of our partners’ share of operating losses associated with synfuel operations, as well as our partners’ $70 million share of the asset impairment charges in 2006.facilities at December 31, 2007. The 2007 decrease reflects the decreasedlower net operating losses in 2007 due to the 2006 one-timeasset impairment charges, partially offset by increased productioncharge we incurred in 2007. The decrease in 2006 reflects reduced operating losses due to the idling of production at all nine of our synfuel facilities from May to October 2006, partially offset by our partners’ $70 million share of the asset impairment. The sale of interests in our synfuel facilities during prior periods resulted in allocating a larger percentage of such losses to our partners.an increased discount on higher sales levels for 2007.
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See Note 3 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
Effective January 1, 2008, we adopted SFAS No. 157,Fair Value Measurements. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff PositionFAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See also the “Fair Value” section.
Effective January 1, 2007, we adopted FASB Interpretation No. (FIN) 48,Accounting for Uncertainty in Income Taxes –— an interpretation of FASB Statement No. 109. The cumulative effect of the adoption of FIN 48 represented a $5 million reduction to the January 1, 2007 balance of retained earnings.
Effective January 1, 2006, we adopted SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. The cumulative effect of the adoption of SFAS 123(R) was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares.
CAPITAL RESOURCES AND LIQUIDITY
Cash Requirements
We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. During 2007,2008, our cash requirements were met primarily through operations and short-term borrowings. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements.from our non-utility monetization program.
Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 20082009 of up to $1.2$1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We may spend an additional $300 million on growth-related projects within our non-utility businesses in 2008.
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We expect non-utility capital spending will approximate $200$175 million to $350$300 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.
Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.
Long-term debt maturing or remarketing in 20082009 totals approximately $450$350 million.
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
| Cash Flow From (Used For) | ||||||||||||||||||||||||
| Operating activities: | ||||||||||||||||||||||||
| Net income | $ | 971 | $ | 433 | $ | 537 | $ | 546 | $ | 971 | $ | 433 | ||||||||||||
| Depreciation, depletion and amortization | 926 | 1,014 | 872 | 899 | 926 | 1,014 | ||||||||||||||||||
| Deferred income taxes | 144 | 28 | 147 | 348 | 144 | 28 | ||||||||||||||||||
| Gain on sale of non-utility business | (900 | ) | — | — | (128 | ) | (900 | ) | — | |||||||||||||||
| Gain on sale of synfuel and other assets, net and synfuel impairment | (253 | ) | 28 | (405 | ) | (35 | ) | (253 | ) | 28 | ||||||||||||||
| Working capital and other | 237 | (47 | ) | (150 | ) | (71 | ) | 237 | (47 | ) | ||||||||||||||
| 1,125 | 1,456 | 1,001 | 1,559 | 1,125 | 1,456 | |||||||||||||||||||
| Investing activities: | ||||||||||||||||||||||||
| Plant and equipment expenditures – utility | (1,035 | ) | (1,126 | ) | (850 | ) | ||||||||||||||||||
| Plant and equipment expenditures – non-utility | (264 | ) | (277 | ) | (215 | ) | ||||||||||||||||||
| Plant and equipment expenditures — utility | (1,183 | ) | (1,035 | ) | (1,126 | ) | ||||||||||||||||||
| Plant and equipment expenditures — non-utility | (190 | ) | (264 | ) | (277 | ) | ||||||||||||||||||
| Acquisitions, net of cash acquired | — | (42 | ) | (50 | ) | — | — | (42 | ) | |||||||||||||||
| Proceeds from sale of non-utility business | 1,262 | — | — | 253 | 1,262 | — | ||||||||||||||||||
| Proceeds from sale of synfuels and other assets | 417 | 313 | 409 | |||||||||||||||||||||
| Proceeds (refunds) from sale of synfuels and other assets | (278 | ) | 417 | 313 | ||||||||||||||||||||
| Restricted cash and other investments | (50 | ) | (62 | ) | (96 | ) | (125 | ) | (50 | ) | (62 | ) | ||||||||||||
| 330 | (1,194 | ) | (802 | ) | (1,523 | ) | 330 | (1,194 | ) | |||||||||||||||
| Financing activities: | ||||||||||||||||||||||||
| Issuance of long-term debt and common stock | 50 | 629 | 1,041 | 1,310 | 50 | 629 | ||||||||||||||||||
| Redemption of long-term debt | (393 | ) | (687 | ) | (1,266 | ) | (446 | ) | (393 | ) | (687 | ) | ||||||||||||
| Repurchase of long-term debt | (238 | ) | — | — | ||||||||||||||||||||
| Short-term borrowings, net | (47 | ) | 291 | 437 | (340 | ) | (47 | ) | 291 | |||||||||||||||
| Repurchase of common stock | (708 | ) | (61 | ) | (13 | ) | (16 | ) | (708 | ) | (61 | ) | ||||||||||||
| Dividends on common stock and other | (370 | ) | (375 | ) | (366 | ) | (354 | ) | (370 | ) | (375 | ) | ||||||||||||
| (1,468 | ) | (203 | ) | (167 | ) | (84 | ) | (1,468 | ) | (203 | ) | |||||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | $ | (13 | ) | $ | 59 | $ | 32 | $ | (48 | ) | $ | (13 | ) | $ | 59 | |||||||||
Cash from Operating Activities
A majority of our operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. Our non-utility businesses also provide sources of
Cash from operations totaling $1.6 billion in 2008, increased $434 million from the comparable 2007 period. The operating cash flow to the enterprise,comparison primarily from the synthetic fuels business, which we believe, subject to considerations discussed below, will provide up to approximately $200 million of cash impacts in 2008 and 2009. We have reported the business activity of the synthetic fuel business as a discontinued operation as of December 31, 2007. Cash flow related to discontinued operations in 2007 includes a gain on sale of interests in synfuel projects of $244 million,reflects higher net income, after adjusting for impairments, partners’ sharenon-cash and non-operating items (depreciation, depletion and amortization, deferred taxes and gains on sales of assets), and cash payments received related to our synfuel project losses of $188 million, and contributions from synfuel partners of $229 million.program hedges.
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Cash from operations totaling $1.1 billion in 2007 decreased $331 million from the comparable 2006 period. The operating cash flow comparison primarily reflects a decrease in net income after adjusting for non-cash items (depreciation, depletion and amortization and deferred taxes) and gains on sales of businesses. The decrease was mostly driven by taxes attributable to our non-utility monetization program.
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Cash from Investing Activities
Cash inflows associated with investing activities are primarily generated from the sale of assets.assets, while cash outflows are primarily generated from plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.
Net cash used for investing activities was approximately $1.5 billion in 2008, compared with cash from investing activities of $330 million in 2007. The change was primarily driven by our non-utility monetization program and final refund payments to our synfuel partners in 2008.
Net cash from investing activities increased $1.5 billion in 2007, due primarily to the sale of our Antrim shale gas exploration and production business and lower capital expenditures.
Cash from Financing Activities
We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by our operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.
Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% to 52%, to ensure it is consistent with our
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objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet. The extension of the average maturity was accomplished at interest rates that lowered our debt costs.
Net cash used for financing activities long-term financing activities, andwas $84 million in 2008, compared to net cash used of approximately $1.5 billion for the funding obligations of our defined benefit pension plans. In response, we have undertaken contingency planning effortssame period in 2007. The change was primarily attributable to mitigate any adverse impacts to our businesses resultingincreased proceeds from the liquidity issues in the credit markets. We have performed an assessmentissuance of our ability to obtain financinglong-term debt, net of debt redemptions and do not anticipate any issues with financing in the public or private markets in 2008. With respect to short-term financing, we have the ability to draw on bank lines if there is a further disruption in the commercial paper market. Additionally, a decrease in the fair valuerepurchases, and lower repurchases of our pension plan assets, which fluctuates based on current market conditions, could result in increased funding requirements to our pension plans. We will continue to monitor developments in the credit markets and the potential impacts on our business.common stock.
Net cash used for financing activities increased $1.3 billion in 2007 primarily related to the repurchase of common stock, a decrease in short-term borrowings and the issuancea lower level of long-term debt issuances, partially offset by lower debt redemptions.
Outlook
We expect cash usedflow from operations to increase over the long-term primarily due to improvements from higher earnings at our utilities. We may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.
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Recent distress in the financial markets has had an adverse impact on financial market activities, including extreme volatility in security prices and severely diminished liquidity and credit availability. Pursuant to the failures of large financial institutions, the credit situation rapidly evolved into a global crisis resulting in a number of international bank failures and declines in various stock indexes, and large reductions in the market value of equities and commodities worldwide. The crisis has led to increased volatility in the markets for both financial and physical assets, as the failures of large financial institutions resulted in sharply reduced trading volumes and activity. The effects of the credit situation will continue to be monitored.
We have experienced difficulties in accessing the commercial paper markets for short-term financing activitiesneeds and an extended period of distress in the capital markets could have a negative impact on our liquidity in the future. Short-term borrowings, principally in the form of commercial paper, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities. Beginning late in the third quarter of 2008, access to the commercial paper markets was sharply reduced and, as a result, we drew against our unsecured credit lines to supplement other sources of funds to meet our short-term liquidity needs. We continue to access the long-term bond markets as evidenced by certain financings completed in the fourth quarter of 2008. Since December 31, 2008, we have benefited from substantially improved liquidity and pricing in the commercial paper market. As a result, we anticipate repayment of our credit facility draws during the first quarter of 2009.
Approximately $1.2 billion of our total short-term credit arrangements of $2.1 billion expire between June and December 2009, with the remainder expiring in October 2010. In anticipation of a significantly more challenging credit market, we expect to pursue the renewal of $975 million of our syndicated revolving credit facilities before their expiration in October. Given current conditions in the credit markets, we anticipate that the new facilities will vary significantly from our current facilities with respect to such items as bank participation, allocation levels, pricing and covenants. We are currently in discussions with our existing bank group and actively pursuing potential new candidates for inclusion, as we anticipate that a number of banks in our current bank group will elect not to participate in the renewal or will alter their commitment level. Initial indications are that pricing is likely to be significantly higher due to market-wide re-pricing of risk. Multi-year agreements are still possible, however, the recent trend in the marketplace is toward 364 day facilities. Several bi-lateral credit facilities totaling approximately $200 million will also expire in 2009 and we are evaluating the need for replacement.
Our benefit plans have not experienced any direct significant impact on liquidity or counterparty risk due to the turmoil in the financial markets. As a result of losses experienced in the financial markets, our benefit plan assets experienced negative returns for 2008, which will result in increased $36 million during 2006 comparedbenefit costs and higher contributions in 2009 and future years than in the recent past or than originally planned.
We have assessed the implications of these factors on our current business and determined that there has not been a significant impact to 2005, due mostlyour financial position and results of operations in 2008. While the impact of continued market volatility and turmoil in the credit markets cannot be predicted, we believe we have sufficient operating flexibility, cash resources and funding sources to a decrease in short-term borrowingsmaintain 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 issuance of common stockinability to access adequate capital could adversely impact earnings and long-term debt, partially offset by lower debt redemptions.cash flows.
See Notes 11 12, and 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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Contractual Obligations
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2008:
| 2014 | ||||||||||||||||||||
Contractual Obligations | Total | 2009 | 2010-2011 | 2012-2013 | and Beyond | |||||||||||||||
| (In millions) | ||||||||||||||||||||
| Long-term debt: | ||||||||||||||||||||
| Mortgage bonds, notes and other | $ | 6,687 | $ | 220 | $ | 1,294 | $ | 671 | $ | 4,502 | ||||||||||
| Securitization bonds | 1,064 | 132 | 290 | 341 | 301 | |||||||||||||||
| Trust preferred-linked securities | 289 | — | — | — | 289 | |||||||||||||||
| Capital lease obligations | 91 | 15 | 26 | 18 | 32 | |||||||||||||||
| Interest | 6,104 | 484 | 884 | 722 | 4,014 | |||||||||||||||
| Operating leases | 238 | 36 | 57 | 46 | 99 | |||||||||||||||
| Electric, gas, fuel, transportation and storage purchase obligations(1) | 5,665 | 2,972 | 1,813 | 160 | 720 | |||||||||||||||
| Other long-term obligations(2)(3)(4) | 201 | 41 | 94 | 25 | 41 | |||||||||||||||
| Total obligations | $ | 20,339 | $ | 3,900 | $ | 4,458 | $ | 1,983 | $ | 9,998 | ||||||||||
| (1) | Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (2) | Includes liabilities for | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (3) | Excludes other long-term | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (4) | At December 31,
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Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.
As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the credit rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the credit rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if the parent is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. While we currently do not anticipate such a
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downgrade, we cannot predict the outcome of current or future credit rating agency reviews. The following table shows our credit rating as determined by three nationally recognized credit rating agencies. All ratings are considered investment grade and affect the value of the related securities.
| Credit Rating Agency | ||||||||
| Standard & | Moody’s | Fitch | ||||||
Entity | Description | Poor’s | Investors Service | Ratings | ||||
| DTE Energy | Senior Unsecured Debt | BBB- | Baa2 | BBB | ||||
| Commercial Paper | A-2 | P-2 | F2 | |||||
| Detroit Edison | Senior Secured Debt | A- | ||||||
| A3 | A- | |||||||
| Commercial Paper | A-2 | P-2 | F2 | |||||
| MichCon | Senior Secured Debt | BBB+ | A3 | BBB+ | ||||
| Commercial Paper | A-2 | P-2 | F2 | |||||
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CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles require that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Additional discussion of these accounting policies can be found in the Notes to Consolidated Financial Statements in Item 8 of this Report.
Regulation
A significant portion of our business is subject to regulation. Detroit Edison and MichCon currently meet the criteria of SFAS No. 71,Accounting for the Effects of Certain Types of Regulation. Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of SFAS No. 71 for some or all of our businesses. Management believes that currently available facts support the continued application of SFAS No. 71 and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment. See Note 5 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Derivatives and Hedging Activities
Risk management and trading activities are accounted for in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,as amended and interpreted. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. All derivatives are recorded at fair value and shown as Derivative Assets or Liabilities in the Consolidated Statements of Financial Position. Derivatives are measured at fair value, and changes in the fair value of the derivative instruments are recognized in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchases and normal sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are not recorded at fair value. Essentially all of the commodity contracts entered into by Detroit Edison and MichCon meet the criteria specified for this exception.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of derivative contracts is
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determined from a combination of active quotes, published indexes and mathematical valuation models. We generally derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods in which external market data is not readily observable, we estimate value using mathematical valuation models. Valuation models require various inputs and assumptions, including forward prices, volatility, interest rates, and exercise periods. For those inputs which are not observable, we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes, current market transactions or other observable market information may require us to record gains or losses at inception of new derivative contracts.
The fair values we calculate for our derivatives may change significantly as inputs and assumptions are updated for new information. Actual cash returns realized on our derivatives may be different from the results we estimate using models. As fair value calculations are estimates based largely on commodity prices, we perform sensitivity analysis on the fair values of our forward contracts. See sensitivity analysis in the Fair Value section. See Notes 15 and 16 of the Notes to Consolidated Financial Statements in Item 8 of this report.
Allowance for Doubtful Accounts
We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends, economic conditions, age of receivables and other information. Higher customer bills due to increased electricity and gas prices, the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As a result of these factors, our allowance for doubtful accounts increased in 2008 and 2007. We believe the allowance for doubtful accounts is based on reasonable estimates. As part of the 2005 gas rate order for MichCon, the MPSC provided for the establishment of an uncollectible accounts tracking mechanism that partially mitigates the impact associated with MichCon uncollectible expenses. Detroit Edison has requested a similar tracking mechanism in its rate request filed January 26, 2009. However, failure to make continued progress in collecting our past due receivables in light of volatile energy prices and deteriorating economic conditions would unfavorably affect operating results and cash flow.
Asset Impairments
Goodwill
Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142,Goodwill and Other Intangible Assets,each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing these impairment tests, we estimate the reporting unit’s fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.
As of December 31, 2008, our goodwill totaled $2 billion with 97 percent of this amount allocated to our utility reporting units. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment.
We performed our annual impairment test on October 1, 2008 and determined that the estimated fair value of our reporting units exceeded their carrying value and no impairment existed. During the fourth quarter of 2008, the closing price of DTE Energy’s stock declined by approximately 11% and at December 31, 2008
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was approximately 3 percent below its book value per share. The market price of an individual equity security (and therefore the market capitalization of an entity with publicly traded equity securities) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over an entity. An acquirer is often willing to pay more for equity securities that give it a controlling interest (i.e. a control premium) than an investor would pay for a number of equity securities representing less than a controlling interest. That control premium may cause the fair value of the entity to exceed its market capitalization. In assessing whether the recent modest decline in the trading price of DTE Energy’s common stock below its book value was an indication of impairment, we considered the following factors: (1) the relatively short duration and modest decline in the trading price of DTE Energy’s common stock; (2) the impact of the national and regional recession on DTE Energy’s future operating results and anticipated cash flows; (3) the favorable results of the recently performed annual impairment test and (4) a comparison of book value to the traded market price, including the impact of a control premium. The implied control premium of approximately 3 percent needed to equate DTE Energy’s market price to its book value was below the low end of the range of control premiums observed in recent transactions. As a result of this assessment, we determined that the decline in market price did not represent a trigger event at December 31, 2008 and an updated impairment test was not performed.
We will continue to monitor our estimates and assumptions regarding future cash flows. While we believe our assumptions are reasonable, actual results may differ from our projections.
Long-Lived Assets
We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate that the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, condition of the asset, or plans to dispose of the asset before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level for which independent cash flows of long-lived assets can be identified from other groups of assets and liabilities. Impairment may occur when the carrying value of the asset exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the long-lived asset over its fair value. An impairment would require us to reduce both the long-lived asset and current period earnings by the amount of the impairment, which would adversely impact our earnings. See Note 4 of Notes to Consolidated Financial Statements in Item 8 of this Report.
Our Power and Industrial Projects segment has long-term contracts with General Motors Corporation (GM) and Ford Motor Company (Ford) to provide onsite energy services at certain of their facilities. At December 31, 2008, the book value of long-lived assets used in the servicing of these facilities was approximately $85 million. In addition, we have an equity investment of approximately $40 million in an entity which provides similar services to Chrysler LLC (Chrysler). These companies are in financial distress, with GM and Chrysler recently receiving loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. We consider the recent announcements by these companies as an indication of possible impairment due to a significant adverse change in the business climate that could affect the value of our long-lived assets as described in SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” and have performed an impairment test on these assets. Based on our current undiscounted cash flow projections we have determined that we do not have an impairment as of December 31, 2008. We have also determined that we do not have an other than temporary decline in our Chrysler-related equity investment as described in APB 18, “The Equity Method of Accounting for Investments in Common Stock.” As the circumstances surrounding the long-term viability of these entities are dynamic and uncertain, we continue to monitor developments as they occur and will update our impairment analyses accordingly.
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Pension and Postretirement Costs
We sponsor defined benefit pension plans and postretirement benefit plans for substantially all of the employees of the Company. The measurement of the plan obligations and cost of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. When determining the various assumptions that are required, we consider historical information as well as future expectations. The benefit costs are affected by, among other things, the actual rate of return on plan assets, the long-term expected return on plan assets, the discount rate applied to benefit obligations, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the anticipated rate of increase of health care costs and the level of benefits provided to employees and retirees. Pension and postretirement benefit costs attributed to the segments are included with labor costs and ultimately allocated to projects within the segments, some of which are capitalized.
We had pension costs for pension plans of $24 million in 2008, $76 million in 2007, and $134 million in 2006. Postretirement benefits costs for all plans were $142 million in 2008, $188 million in 2007 and $197 million in 2006. Pension and postretirement benefits costs for 2008 are calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 8.75%. In developing our expected long-term rate of return assumption, we evaluated asset class risk and return expectations, as well as inflation assumptions. Projected returns are based on broad equity, bond and other markets. Our 2009 expected long-term rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 55% in equity markets, 20% in fixed income markets, and 25% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we believe that 8.75% is a reasonable long-term rate of return on our plan assets for 2009. We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.
We calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” allow the MRV of plan assets to be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For our pension plans, we use a calculated value when determining the MRV of the pension plan assets and recognize changes in fair value over a three-year period. Accordingly, the future value of assets will be impacted as previously deferred gains or losses are recorded. Volatile financial markets contributed to our investment performance resulting in unrecognized net losses. As of December 31, 2008, we had $1.1 billion of cumulative losses that remain to be recognized in the calculation of the MRV of pension assets. For our postretirement benefit plans, we use fair value when determining the MRV of postretirement benefit plan assets, therefore all investment losses and gains have been recognized in the calculation of MRV for these plans.
The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a yield curve approach and a review of bonds that receive one of the two highest ratings given by a recognized rating agency. The yield curve approach matches projected plan pension and postretirement benefit payment streams with bond portfolios reflecting actual liability duration unique to our plans. The discount rate determined on this basis increased from 6.5% at December 31, 2007 to 6.9% at December 31, 2008. Due to the combination of recent company contributions, losses on plan assets due to negative financial market performance and higher discount rates, we estimate that our 2009 total pension costs will approximate $57 million compared to $24 million in 2008 and our 2009 postretirement benefit costs will approximate $208 million compared to $142 million in 2008. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. The pension cost tracking mechanism, implemented in November 2004, that provided for recovery or refunding of pension costs above or below amounts reflected in Detroit Edison’s base rates, at the request of Detroit Edison was not reauthorized by the MPSC in its rate order effective January 1, 2009. In April 2005,
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the MPSC approved the deferral of the non-capitalized portion of MichCon’s negative pension expense. MichCon will record a regulatory liability for any negative pension costs, as determined under generally accepted accounting principles.
Lowering the expected long-term rate of return on our plan assets by one-percentage-point would have increased our 2008 pension costs by approximately $39 million. Lowering the discount rate and the salary increase assumptions by one-percentage-point would have increased our 2008 pension costs by approximately $37 million. Lowering the health care cost trend assumptions by one-percentage-point would have decreased our postretirement benefit service and interest costs for 2008 by approximately $26 million.
At December 31, 2006, we adopted SFAS No. 158 and recognized the underfunded status of our pension and other postretirement plans. The impact of the adoption of SFAS No. 158 was an increase in pension and postretirement benefit liabilities of approximately $1.3 billion in 2006. We requested and received agreement from the MPSC to record the additional liability amounts for the Detroit Edison and MichCon benefit plans on the Statement of Financial Position as a regulatory asset. As a result, regulatory assets were increased by approximately $1.2 billion. The remainder of the increase in pension and postretirement benefit liabilities is included in accumulated other comprehensive loss, net of tax. In 2008, as required by SFAS 158, we changed the measurement date of our pension and postretirement benefit plans from November 30 to December 31. As a result we recognized adjustments of $17 million ($9 million after-tax) and $4 million to retained earnings and regulatory liabilities, respectively, which represents approximately one month of pension and other postretirement benefit cost for the period from December 1, 2007 to December 31, 2008.
The market value of our pension and postretirement benefit plan assets has been affected in a negative manner by the financial markets. The value of our plan assets was $3.8 billion at November 30, 2007 and $2.8 billion at December 31, 2008. At December 31, 2008 our pension plans were underfunded by $877 million and our other postretirement benefit plans were underfunded by $1.4 billion, reflected in noncurrent assets, current liabilities, and noncurrent liabilities, respectively. The decline relative to 2007 funding levels results from negative investment performance returns in 2008.
Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made contributions to our pension plans of $100 million and $150 million in 2008 and 2007, respectively. Also, we contributed $50 million to our pension plans in January 2009. At the discretion of management, consistent with the Pension Protection Act of 2006, and depending upon financial market conditions, we anticipate making up to a $250 million contribution to our pension plans in 2009 and up to $1.1 billion over the next five years. We made postretirement benefit plan contributions of $116 million and $76 million in 2008 and 2007, respectively. In January 2009, we contributed $40 million to our postretirement benefit plans. We are required by orders issued by the MPSC to make postretirement benefit contributions at least equal to the amounts included in Detroit Edison’s and MichCon’s base rates. As a result, we expect to make up to a $130 million contribution to our postretirement plans in 2009 and, subject to MPSC funding requirements, up to $750 million over the next five years.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $14 million in 2008, $16 million in 2007, and $17 million in 2006.
See Note 18 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Legal Reserves
We are involved in various legal proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate. Legal reserves are based upon management’s assessment of pending and threatened legal proceedings and claims against us.
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Insured and Uninsured Risks
Our comprehensive insurance program provides coverage for various types of risks. Our insurance policies cover risk of loss including property damage, general liability, workers’ compensation, auto liability, and directors’ and officers’ liability. Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. The maximum self-insured retention for various risks is as follows: property damage - $10 million, general liability — $7 million, workers’ compensation — $9 million, and auto liability — $7 million. We have an actuarially determined estimate of our incurred but not reported (IBNR) liability prepared annually and we adjust our reserves for self-insured risks as appropriate. As of December 31, 2008, this IBNR liability was approximately $39 million.
Accounting for Tax Obligations
We are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate our obligations to taxing authorities. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement in accordance with FIN 48,Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. If the benefit does not meet the more likely than not criteria for being sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We also have non-income tax obligations related to property, sales and use and employment-related taxes and ongoing appeals related to these tax matters that are outside the scope of FIN 48 and accounted for under SFAS No. 5 and FASB Statement of Financial Accounting Concepts No. 6.
Accounting for tax obligations requires judgments, including assessing whether tax benefits are more likely than not to be sustained, and estimating reserves for potential adverse outcomes regarding tax positions that have been taken. We also assess our ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. We do not record valuation allowances for deferred tax assets related to capital losses that we believe will be realized in future periods. While we believe the resulting tax reserve balances as of December 31, 2008 and December 31, 2007 are appropriately accounted for in accordance with FIN 48, SFAS No. 5, SFAS No. 109 and FASB Statement of Financial Accounting Concepts No. 6, as applicable, the ultimate outcome of such matters could result in favorable or unfavorable adjustments to our consolidated financial statements and such adjustments could be material. See Note 8 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
ENVIRONMENTAL MATTERS
Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which DTE or its subsidiaries, including Detroit Edison and MichCon are responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the time of the remediation work, changes in technology, regulations and the requirements of local governmental authorities. These matters, if resolved in a manner different from the estimates, could have a material effect on our results of operation and financial position, to the extent the costs are not recovered through the base rates set for our utilities. See Note 17 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 2 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
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FAIR VALUE
SFAS No. 157 — Fair Value Measurements
Effective January 1, 2008, we adopted SFAS No. 157. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. As permitted by FASB Staff PositionFAS 157-2, we have deferred the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. See Note 15 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Derivative Accounting
The accounting standards for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as Derivative assets or liabilities, at the fair value of the contract. The recorded fair value of the contract is then adjusted at each reporting date, in the Consolidated Statements of Operations, to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting. Changes in the fair value of a designated derivative that is highly effective as a cash flow hedge are recorded as a component of Accumulated other comprehensive income, net of taxes, until the hedged item affects income. These amounts are subsequently reclassified into earnings as a component of the value of the forecasted transaction, in the same period as the forecasted transaction affects earnings. The ineffective portion of the fair value changes is recognized in the Consolidated Statements of Operations immediately.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of derivative contracts are determined from a combination of quoted market prices, published indexes and mathematical valuation models. Where possible, we derive the pricing for our contracts from active quotes or external resources. Actively quoted indexes include exchange-traded positions such as the New York Mercantile Exchange and the Intercontinental Exchange, and over-the-counter positions for which broker quotes are available. For periods or locations in which external market data is not readily observable, we estimate value using mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates and exercise periods. For those inputs which are not observable, we use model-based extrapolation, proxy techniques or historical analysis to derive the required valuation inputs. We periodically update our policy and valuation methodologies for changes in market liquidity and other assumptions which may impact the estimated fair value of our derivative contracts. Liquidity and transparency in energy markets where fair value is evidenced by market quotes, current market transactions or other observable market information may require us to record gains or losses at inception of new derivative contracts. Our credit risk and the credit risk of our counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the year ended December 31, 2008.
Contracts we typically classify as derivative instruments include power, gas, certain coal and oil forwards, futures, options and swaps, and foreign currency contracts. Items we do not generally account for as derivatives include proprietary gas inventory, certain gas storage and transportation arrangements, and gas and oil reserves.
We manage our MTM risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based on the commodity (e.g. electricity or gas), the product (e.g. electricity for delivery during peak or off-peak hours), the delivery location (e.g. by region), the risk profile (e.g. forward or option), and the delivery period (e.g. by month and year).
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The subsequent tables contain the following four categories represented by their operating characteristics and key risks:
| Proprietary | Structured | Economic | ||||||||||||||||||
| (in Millions) | Trading | Contracts | Hedges | Other | Total | |||||||||||||||
| MTM at December 31, 2006 | $ | (9 | ) | $ | (2 | ) | $ | (36 | ) | $ | (24 | ) | $ | (71 | ) | |||||
| Reclassed to realized upon settlement | 22 | 1 | 17 | 16 | 56 | |||||||||||||||
| Changes in fair value recorded to income | 4 | (57 | ) | 23 | (220 | )(1) | (250 | ) | ||||||||||||
| Amortization of option premiums | (10 | ) | (2 | ) | — | (101 | )(2) | (113 | ) | |||||||||||
| Amounts recorded to unrealized income | 16 | (58 | ) | 40 | (305 | ) | (307 | ) | ||||||||||||
| Amounts recorded in Other comprehensive Income | — | — | — | (1 | ) | (1 | ) | |||||||||||||
| Transfer of contracts | — | (323 | ) | — | 323 | — | ||||||||||||||
| Option premiums paid and other | 1 | 37 | — | 9 | 47 | |||||||||||||||
| MTM at December 31, 2007 | $ | 8 | $ | (346 | ) | $ | 4 | $ | 2 | $ | (332 | ) | ||||||||
Unconventional Gas reserves. A substantial portion of the Company’s price risk related to its Antrim shaleassociated with anticipated production from the Barnett natural gas exploration and production business hadreserves has been mitigated by financial contracts that hedged our price risk exposure through 2013. These financial contracts were accounted for as cash flow hedges, with changes2010. Changes in estimated fairthe value of the contracts reflectedhedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income. Uponincome to the sale of Antrim,extent that the financial contracts no longer qualified as cash flow hedges.hedges are deemed effective. The contracts were retained and offsetting financial contracts were put into place to effectively settle these positions.
| Proprietary | Structured | Economic | Assets | |||||||||||||||||||||
| (in Millions) | Trading | Contracts | Hedges | Eliminations | Other | (Liabilities) | ||||||||||||||||||
| Current assets | $ | 35 | $ | 135 | $ | 29 | $ | (9 | ) | $ | 5 | $ | 195 | |||||||||||
| Noncurrent assets | 9 | 194 | 8 | (4 | ) | — | 207 | |||||||||||||||||
| Total MTM assets | 44 | 329 | 37 | (13 | ) | 5 | 402 | |||||||||||||||||
| Current liabilities | (34 | ) | (234 | ) | (23 | ) | 9 | — | (282 | ) | ||||||||||||||
| Noncurrent liabilities | (2 | ) | (441 | ) | (10 | ) | 4 | (3 | ) | (452 | ) | |||||||||||||
| Total MTM liabilities | (36 | ) | (675 | ) | (33 | ) | 13 | (3 | ) | (734 | ) | |||||||||||||
| Total MTM net assets (liabilities) | $ | 8 | $ | (346 | ) | $ | 4 | $ | — | $ | 2 | $ | (332 | ) | ||||||||||
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As a result of adherence to generally accepted accounting principles, the tables below do not include the expected earnings impacts of certain non-derivative gas storage, transportation and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy’s reportedperiod-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical deliveryand/or settlement.
The following tables provide details on changes in our MTM net asset (or liability) position during 2008:
| Economic | Structured | Proprietary | ||||||||||||||||||
| Hedges | Contracts | Trading | Other | Total | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| MTM at December 31, 2007 | $ | 4 | $ | (365 | ) | $ | 8 | $ | 2 | $ | (351 | ) | ||||||||
| Reclassify to realized upon settlement | (17 | ) | 47 | 11 | (2 | ) | 39 | |||||||||||||
| Changes in fair value recorded to income | 34 | 89 | 20 | 1 | 144 | |||||||||||||||
| Changes in fair value recorded in regulatory liabilities | — | — | — | 2 | 2 | |||||||||||||||
| Amortization of option premiums | — | (1 | ) | (1 | ) | — | (2 | ) | ||||||||||||
| Amounts recorded to income | 17 | 135 | 30 | 1 | 183 | |||||||||||||||
| Cumulative effect adjustment to initially apply SFAS No. 157, pre-tax | — | 7 | — | — | 7 | |||||||||||||||
| Amounts recorded in other comprehensive income | — | — | — | 6 | 6 | |||||||||||||||
| Change in collateral held by (for) others | (3 | ) | (7 | ) | (6 | ) | — | (16 | ) | |||||||||||
| Option premiums paid and other | — | 8 | (10 | ) | — | (2 | ) | |||||||||||||
| MTM at December 31, 2008 | $ | 18 | $ | (222 | ) | $ | 22 | $ | 9 | $ | (173 | ) | ||||||||
A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business was mitigated by financial contracts that hedged our price risk exposure through 2013. The contracts were retained when the Antrim business was sold and offsetting financial contracts were put into place to effectively settle these positions. The contracts will require payments through 2013. These contracts represent a significant portion of the above net mark-to-market liability.
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The following table provides a current and noncurrent analysis of Derivative assets and liabilities, as reflected on the Consolidated Statements of Financial Position as of December 31, 2008. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.
| Economic | Structured | Proprietary | Assets | |||||||||||||||||||||
| Hedges | Contracts | Trading | Eliminations | Other | (Liabilities) | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Current assets | $ | 36 | $ | 165 | $ | 116 | $ | (9 | ) | $ | 8 | $ | 316 | |||||||||||
| Noncurrent assets | 8 | 129 | 3 | (1 | ) | 1 | 140 | |||||||||||||||||
| Total MTM assets | 44 | 294 | 119 | (10 | ) | 9 | 456 | |||||||||||||||||
| Current liabilities | (15 | ) | (209 | ) | (70 | ) | 9 | — | (285 | ) | ||||||||||||||
| Noncurrent liabilities | (11 | ) | (307 | ) | (27 | ) | 1 | — | (344 | ) | ||||||||||||||
| Total MTM liabilities | (26 | ) | (516 | ) | (97 | ) | 10 | — | (629 | ) | ||||||||||||||
| Total MTM net assets (liabilities) | $ | 18 | $ | (222 | ) | $ | 22 | $ | — | $ | 9 | $ | (173 | ) | ||||||||||
The table below shows the maturity of our MTM positions:
| 2012 | ||||||||||||||||||||
| and | Total Fair | |||||||||||||||||||
Source of Fair Value | 2009 | 2010 | 2011 | Beyond | Value | |||||||||||||||
| (In millions) | ||||||||||||||||||||
| Economic Hedges | $ | 21 | $ | (7 | ) | $ | (2 | ) | $ | 6 | $ | 18 | ||||||||
| Structured Contracts | (45 | ) | (64 | ) | (44 | ) | (69 | ) | (222 | ) | ||||||||||
| Proprietary Trading | 46 | (24 | ) | — | — | 22 | ||||||||||||||
| Other | 9 | — | — | — | 9 | |||||||||||||||
| Total | $ | 31 | $ | (95 | ) | $ | (46 | ) | $ | (63 | ) | $ | (173 | ) | ||||||
| 2011 | ||||||||||||||||||||
| (in Millions) | and | Total Fair | ||||||||||||||||||
| Source of Fair Value | 2008 | 2009 | 2010 | Beyond | Value | |||||||||||||||
| Proprietary Trading | $ | 1 | $ | 7 | $ | — | $ | — | $ | 8 | ||||||||||
| Structured Contracts | (99 | ) | (78 | ) | (52 | ) | (117 | ) | (346 | ) | ||||||||||
| Economic Hedges | 6 | — | (2 | ) | — | 4 | ||||||||||||||
| Other | 5 | (2 | ) | (1 | ) | — | 2 | |||||||||||||
| Total | $ | (87 | ) | $ | (73 | ) | $ | (55 | ) | $ | (117 | ) | $ | (332 | ) | |||||
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Market Price Risk
DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.
The Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. Further, changes in the price of electricity can impact the level of exposure of Customer Choice programs and uncollectible expenses at the Electric Utility. In addition, changes in the price of natural gas can impact the valuation of lost gas, storage sales revenue and uncollectible expenses at the Gas Utility. However, the Company does not bear significant exposure to earnings risk as such changes are included in regulatory rate-recovery mechanisms. Regulatory rate-recovery occurs in the form of PSCR and GCR mechanisms (see Note 1 of the Notes to Consolidated Financial Statements in Item 8 of this Report) and tracking mechanisms to mitigate some losses from customer migration due to electric Customer Choice programs and uncollectible accounts receivable at MichCon. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.
Our Power and Industrial Projects business segment is subject to crude oil, electricity, natural gas, coal and coal-based product price risk and other risks associated with the weakened U.S. economy including constricted capital and credit markets. To the extent that commodity price risk has not been mitigated through the use of long-term contracts, we manage this exposure using forward energy, capacity and futures contracts.
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Our Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we may use forward energy and futures contracts.
Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign currency price fluctuations. These risks are managed by our energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.
Our Gas Midstream business segment has limited exposure to natural gas price fluctuations. The Gas Midstream business unit manages its exposure through the sale of long-term storage and transportation contracts.
Credit Risk
Bankruptcies
We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable loss. We believe our previously accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on our financial statements.
Our utilities and certain non-utility businesses provide services to the domestic automotive industry, including GM, Ford and Chrysler and many of their vendors and suppliers. GM and Chrysler have recently received loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. In February 2009, GM and Chrysler submitted viability plans to the U.S. Government indicating that additional loans were necessary to continue operations in the short term. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on our results, particularly in our Electric Utility and Power and Industrial Projects segments. As the circumstances surrounding the viability of these entities are dynamic and uncertain, we continue to monitor developments as they occur.
Other
We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.
Trading Activities
We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally
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generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of December 31, 2008:
| Credit Exposure | ||||||||||||
| before Cash | Cash | Net Credit | ||||||||||
| Collateral | Collateral | Exposure | ||||||||||
| (In millions) | ||||||||||||
| Investment Grade(1) | ||||||||||||
| A- and Greater | $ | 314 | $ | (14 | ) | $ | 300 | |||||
| BBB+ and BBB | 253 | — | 253 | |||||||||
| BBB- | 47 | — | 47 | |||||||||
| Total Investment Grade | 614 | (14 | ) | 600 | ||||||||
| Non-investment grade(2) | 25 | (1 | ) | 24 | ||||||||
| Internally Rated — investment grade(3) | 206 | (2 | ) | 204 | ||||||||
| Internally Rated — non-investment grade(4) | 28 | (4 | ) | 24 | ||||||||
| Total | $ | 873 | $ | (21 | ) | $ | 852 | |||||
| (1) | This category includes counterparties with minimum credit ratings of
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate Risk
DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of December 31, 2008, we had a floating rate debt-to-total debt ratio of approximately 12% (excluding securitized debt).
Foreign Currency Risk
We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through January 2013. Additionally, we may enter into fair value currency hedges to mitigate changes in the value of contracts or loans.
Summary of Sensitivity Analysis
We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing
65
forward rates at December 31, 2008 by a hypothetical 10% and calculating the resulting change in the fair values.
The results of the sensitivity analysis calculations follow:
| Assuming a 10% | Assuming a 10% | |||||||||
Activity | increase in rates | decrease in rates | Change in the fair value of | |||||||
| (In millions) | ||||||||||
| Coal Contracts | $ | 1 | $ | (1 | ) | Commodity contracts | ||||
| Gas Contracts | $ | (13 | ) | $ | 13 | Commodity contracts | ||||
| Oil Contracts | $ | 1 | $ | (1 | ) | Commodity contracts | ||||
| Power Contracts | $ | 3 | $ | (2 | ) | Commodity contracts | ||||
| Interest Rate Risk | $ | (317 | ) | $ | 346 | Long-term debt | ||||
| Foreign Currency Risk | $ | 5 | $ | (5 | ) | Forward contracts | ||||
| Discount Rates | $ | 1 | $ | (1 | ) | Commodity contracts | ||||
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The following consolidated financial statements and schedules are included herein.
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67
Controls and Procedures
69
(a)
Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange ActRules 13a-15(e) and15d-15(e)) as of December 31, 2008, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.
| (b) | Management’s report on internal control over financial reporting |
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of the effectiveness to future periods are subject to the risks that a control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.Based on our assessment, management believes that, as of December 31, 2008, the Company’s internal control over financial reporting was effective based on those criteria.
The Company’s independent registered public accounting firm that audited the financial statements included in this annual report has issued an attestation report on the Company’s internal control over financial reporting.
(c) | Changes in internal control over financial reporting |
There have been no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
We have audited the consolidated statements of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, cash flows, and changes in shareholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy Company and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, present fairly, in all material respects, the information set forth therein.
70
71
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Detroit, Michigan
February 27, 2009
69
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of DTE Energy Company:
We have audited the internal control over financial reporting of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2008, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2008 of the Company and our report dated February 27, 2009 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
Detroit, Michigan
February 27, 2009
70
DTEEnergy Company
Consolidated Statements of Operations
Consolidated Statements of Operations
| Year Ended December 31 | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions, Except per share amounts) | ||||||||||||
Operating Revenues | $ | 9,329 | $ | 8,475 | $ | 8,157 | ||||||
Operating Expenses | ||||||||||||
| Fuel, purchased power and gas | 4,306 | 3,552 | 3,047 | |||||||||
| Operation and maintenance | 2,694 | 2,892 | 2,677 | |||||||||
| Depreciation, depletion and amortization | 901 | 932 | 990 | |||||||||
| Taxes other than income | 304 | 357 | 309 | |||||||||
| Gain on sale of non-utility business | (128 | ) | (900 | ) | — | |||||||
| Other asset (gains) and losses, reserves and impairments, net | (11 | ) | 37 | 67 | ||||||||
| 8,066 | 6,870 | 7,090 | ||||||||||
Operating Income | 1,263 | 1,605 | 1,067 | |||||||||
Other (Income) and Deductions | ||||||||||||
| Interest expense | 503 | 533 | 525 | |||||||||
| Interest income | (19 | ) | (25 | ) | (26 | ) | ||||||
| Other income | (104 | ) | (93 | ) | (61 | ) | ||||||
| Other expenses | 64 | 35 | 93 | |||||||||
| 444 | 450 | 531 | ||||||||||
Income Before Income Taxes and Minority Interest | 819 | 1,155 | 536 | |||||||||
Income Tax Provision | 288 | 364 | 146 | |||||||||
Minority Interest | 5 | 4 | 1 | |||||||||
Income from Continuing Operations | 526 | 787 | 389 | |||||||||
Discontinued Operations | ||||||||||||
| Income (Loss) from discontinued operations, net of tax | 22 | (4 | ) | (208 | ) | |||||||
| Minority interest in discontinued operations | 2 | (188 | ) | (251 | ) | |||||||
| 20 | 184 | 43 | ||||||||||
Cumulative Effect of Accounting Changes, net of tax | — | — | 1 | |||||||||
Net Income | $ | 546 | $ | 971 | $ | 433 | ||||||
Basic Earnings per Common Share | ||||||||||||
| Income from continuing operations | $ | 3.24 | $ | 4.64 | $ | 2.19 | ||||||
| Discontinued operations | .13 | 1.09 | .24 | |||||||||
| Cumulative effect of accounting changes | — | — | .01 | |||||||||
| Total | $ | 3.37 | $ | 5.73 | $ | 2.44 | ||||||
Diluted Earnings per Common Share | ||||||||||||
| Income from continuing operations | $ | 3.23 | $ | 4.62 | $ | 2.18 | ||||||
| Discontinued operations | .13 | 1.08 | .24 | |||||||||
| Cumulative effect of accounting changes | — | — | .01 | |||||||||
| Total | $ | 3.36 | $ | 5.70 | $ | 2.43 | ||||||
Weighted Average Common Shares Outstanding | ||||||||||||
| Basic | 162 | 169 | 177 | |||||||||
| Diluted | 163 | 170 | 178 | |||||||||
Dividends Declared per Common Share | $ | 2.12 | $ | 2.12 | $ | 2.075 | ||||||
See Notes to Consolidated Financial Statements
71
DTE Energy Company
Consolidated Statements of Financial Position
Consolidated Statements of Financial Position
| December 31 | ||||||||
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
| Cash and cash equivalents | $ | 86 | $ | 123 | ||||
| Restricted cash | 86 | 140 | ||||||
| Accounts receivable (less allowance for doubtful accounts of $265 and $182, respectively) | ||||||||
| Customer | 1,666 | 1,658 | ||||||
| Other | 166 | 514 | ||||||
| Accrued power and gas supply cost recovery revenue | 22 | 76 | ||||||
| Inventories | ||||||||
| Fuel and gas | 333 | 429 | ||||||
| Materials and supplies | 206 | 204 | ||||||
| Deferred income taxes | 227 | 387 | ||||||
| Derivative assets | 316 | 181 | ||||||
| Other | 220 | 196 | ||||||
| Current assets held for sale | — | 83 | ||||||
| 3,328 | 3,991 | |||||||
Investments | ||||||||
| Nuclear decommissioning trust funds | 685 | 824 | ||||||
| Other | 595 | 446 | ||||||
| 1,280 | 1,270 | |||||||
Property | ||||||||
| Property, plant and equipment | 20,065 | 18,809 | ||||||
| Less accumulated depreciation and depletion | (7,834 | ) | (7,401 | ) | ||||
| 12,231 | 11,408 | |||||||
Other Assets | ||||||||
| Goodwill | 2,037 | 2,037 | ||||||
| Regulatory assets | 4,231 | 2,786 | ||||||
| Securitized regulatory assets | 1,001 | 1,124 | ||||||
| Intangible assets | 70 | 25 | ||||||
| Notes receivable | 115 | 87 | ||||||
| Derivative assets | 140 | 199 | ||||||
| Prepaid pension assets | — | 152 | ||||||
| Other | 157 | 116 | ||||||
| Noncurrent assets held for sale | — | 547 | ||||||
| 7,751 | 7,073 | |||||||
Total Assets | $ | 24,590 | $ | 23,742 | ||||
See Notes to Consolidated Financial Statements
72
DTE Energy Company
Consolidated Statements of Financial Position
Consolidated Statements of Financial Position
| December 31 | ||||||||
| 2008 | 2007 | |||||||
| (In millions, except shares) | ||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
| Accounts payable | $ | 899 | $ | 1,189 | ||||
| Accrued interest | 119 | 112 | ||||||
| Dividends payable | 86 | 87 | ||||||
| Short-term borrowings | 744 | 1,084 | ||||||
| Current portion long-term debt, including capital leases | 362 | 454 | ||||||
| Derivative liabilities | 285 | 281 | ||||||
| Deferred gains and reserves | 3 | 400 | ||||||
| Other | 515 | 566 | ||||||
| Current liabilities associated with assets held for sale | — | 48 | ||||||
| 3,013 | 4,221 | |||||||
Long-Term Debt (net of current portion) | ||||||||
| Mortgage bonds, notes and other | 6,458 | 5,576 | ||||||
| Securitization bonds | 932 | 1,065 | ||||||
| Trust preferred-linked securities | 289 | 289 | ||||||
| Capital lease obligations | 62 | 41 | ||||||
| 7,741 | 6,971 | |||||||
Other Liabilities | ||||||||
| Deferred income taxes | 1,958 | 1,824 | ||||||
| Regulatory liabilities | 1,202 | 1,168 | ||||||
| Asset retirement obligations | 1,340 | 1,277 | ||||||
| Unamortized investment tax credit | 96 | 108 | ||||||
| Derivative liabilities | 344 | 450 | ||||||
| Liabilities from transportation and storage contracts | 111 | 126 | ||||||
| Accrued pension liability | 871 | 68 | ||||||
| Accrued postretirement liability | 1,434 | 1,094 | ||||||
| Nuclear decommissioning | 114 | 134 | ||||||
| Other | 328 | 318 | ||||||
| Noncurrent liabilities associated with assets held for sale | — | 82 | ||||||
| 7,798 | 6,649 | |||||||
Commitments and Contingencies (Notes 5, 6, and 17) | ||||||||
Minority Interest | 43 | 48 | ||||||
Shareholders’ Equity | ||||||||
| Common stock, without par value, 400,000,000 shares authorized, 163,019,596 and 163,232,095 shares issued and outstanding, respectively | 3,175 | 3,176 | ||||||
| Retained earnings | 2,985 | 2,790 | ||||||
| Accumulated other comprehensive loss | (165 | ) | (113 | ) | ||||
| 5,995 | 5,853 | |||||||
Total Liabilities and Shareholders’ Equity | $ | 24,590 | $ | 23,742 | ||||
See Notes to Consolidated Financial Statements
73
| Year Ended December 31 | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
Operating Activities | ||||||||||||
| Net income | $ | 546 | $ | 971 | $ | 433 | ||||||
| Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
| Depreciation, depletion and amortization | 899 | 926 | 1,014 | |||||||||
| Deferred income taxes | 348 | 144 | 28 | |||||||||
| Gain on sale of non-utility business | (128 | ) | (900 | ) | — | |||||||
| Other asset (gains), losses and reserves, net | (4 | ) | (9 | ) | (11 | ) | ||||||
| Gain on sale of interests in synfuel projects | (31 | ) | (248 | ) | (38 | ) | ||||||
| Impairment of synfuel projects | — | 4 | 77 | |||||||||
| Partners’ share of synfuel project gains (losses) | 2 | (188 | ) | (251 | ) | |||||||
| Contributions from synfuel partners | 14 | 229 | 197 | |||||||||
| Cumulative effect of accounting changes | — | — | (1 | ) | ||||||||
| Changes in assets and liabilities, exclusive of changes shown separately (Note 1) | (87 | ) | 196 | 8 | ||||||||
| Net cash from operating activities | 1,559 | 1,125 | 1,456 | |||||||||
Investing Activities | ||||||||||||
| Plant and equipment expenditures — utility | (1,183 | ) | (1,035 | ) | (1,126 | ) | ||||||
| Plant and equipment expenditures — non-utility | (190 | ) | (264 | ) | (277 | ) | ||||||
| Acquisitions, net of cash acquired | — | — | (42 | ) | ||||||||
| Proceeds from sale of interests in synfuel projects | 84 | 447 | 246 | |||||||||
| Refunds to synfuel partners | (387 | ) | (115 | ) | — | |||||||
| Proceeds from sale of non-utility business | 253 | 1,262 | — | |||||||||
| Proceeds from sale of other assets, net | 25 | 85 | 67 | |||||||||
| Restricted cash | 54 | 6 | (21 | ) | ||||||||
| Proceeds from sale of nuclear decommissioning trust fund assets | 232 | 286 | 253 | |||||||||
| Investment in nuclear decommissioning trust funds | (255 | ) | (323 | ) | (284 | ) | ||||||
| Other investments | (156 | ) | (19 | ) | (10 | ) | ||||||
| Net cash from (used) for investing activities | (1,523 | ) | 330 | (1,194 | ) | |||||||
Financing Activities | ||||||||||||
| Issuance of long-term debt | 1,310 | 50 | 612 | |||||||||
| Redemption of long-term debt | (446 | ) | (393 | ) | (687 | ) | ||||||
| Repurchase of long-term debt | (238 | ) | — | — | ||||||||
| Short-term borrowings, net | (340 | ) | (47 | ) | 291 | |||||||
| Issuance of common stock | — | — | 17 | |||||||||
| Repurchase of common stock | (16 | ) | (708 | ) | (61 | ) | ||||||
| Dividends on common stock | (344 | ) | (364 | ) | (365 | ) | ||||||
| Other | (10 | ) | (6 | ) | (10 | ) | ||||||
| Net cash used for financing activities | (84 | ) | (1,468 | ) | (203 | ) | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (48 | ) | (13 | ) | 59 | |||||||
Cash and Cash Equivalents Reclassified (to) from Assets Held for Sale | 11 | (11 | ) | — | ||||||||
Cash and Cash Equivalents at Beginning of Period | 123 | 147 | 88 | |||||||||
Cash and Cash Equivalents at End of Period | $ | 86 | $ | 123 | $ | 147 | ||||||
See Notes to Consolidated Financial Statements
74
DTE Energy Company
Consolidated Statements of Changes in Shareholders’ Equity
Consolidated Statements of Changes in Shareholders’ Equity
| Accumulated | ||||||||||||||||||||
| Common Stock | Retained | Other Comprehensive | ||||||||||||||||||
| Shares | Amount | Earnings | Loss | Total | ||||||||||||||||
| (Dollars in millions, shares in thousands) | ||||||||||||||||||||
| Balance, December 31, 2005 | 177,814 | $ | 3,483 | $ | 2,557 | $ | (271 | ) | $ | 5,769 | ||||||||||
| Net income | — | — | 433 | — | 433 | |||||||||||||||
| Issuance of new shares | 411 | 17 | — | — | 17 | |||||||||||||||
| Dividends declared on common stock | — | — | (368 | ) | — | (368 | ) | |||||||||||||
| Repurchase and retirement of common stock | (1,283 | ) | (32 | ) | (29 | ) | — | (61 | ) | |||||||||||
| Adjustment to initially apply SFAS No. 158, net of tax | — | — | — | (38 | ) | (38 | ) | |||||||||||||
| Benefit obligations, net of tax | — | — | — | 3 | 3 | |||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 102 | 102 | |||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | (7 | ) | (7 | ) | |||||||||||||
| Stock-based compensation and other | 196 | (1 | ) | — | — | (1 | ) | |||||||||||||
| Balance, December 31, 2006 | 177,138 | 3,467 | 2,593 | (211 | ) | 5,849 | ||||||||||||||
| Net income | — | — | 971 | — | 971 | |||||||||||||||
| Implementation of FIN 48 | — | — | (5 | ) | — | (5 | ) | |||||||||||||
| Dividends declared on common stock | — | — | (358 | ) | — | (358 | ) | |||||||||||||
| Repurchase and retirement of common stock | (14,440 | ) | (297 | ) | (411 | ) | — | (708 | ) | |||||||||||
| Benefit obligations, net of tax | — | — | — | 6 | 6 | |||||||||||||||
| Net change in unrealized losses on derivatives, net of tax | — | — | — | 91 | 91 | |||||||||||||||
| Net change in unrealized losses on investments, net of tax | — | — | — | 1 | 1 | |||||||||||||||
| Stock-based compensation and other | 534 | 6 | — | — | 6 | |||||||||||||||
| Balance, December 31, 2007 | 163,232 | 3,176 | 2,790 | (113 | ) | 5,853 | ||||||||||||||
| Net income | — | — | 546 | — | 546 | |||||||||||||||
| Implementation of SFAS No. 157, net of tax | — | — | 4 | — | 4 | |||||||||||||||
| Implementation of SFAS No. 158 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 exchange 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 | ) | |||||||||||||
| Stock-based compensation and other | 267 | 15 | — | — | 15 | |||||||||||||||
Balance, December 31, 2008 | 163,020 | $ | 3,175 | $ | 2,985 | $ | (165 | ) | $ | 5,995 | ||||||||||
See Notes to Consolidated Financial Statements
75
DTE Energy Company
Consolidated Statements of Comprehensive Income
Consolidated Statements of Comprehensive Income
The following table displays comprehensive income:
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Net income | $ | 546 | $ | 971 | $ | 433 | ||||||
| Other comprehensive income (loss), net of tax: | ||||||||||||
| Foreign currency translation, net of taxes of $(1), $- and $- | (2 | ) | — | — | ||||||||
| Benefit obligations, net of taxes of $(12), $3 and $2 | (22 | ) | 6 | 3 | ||||||||
| Net unrealized gains (losses) on derivatives: | ||||||||||||
| Gains (losses) arising during the period, net of taxes of $2, $(76) and $3 | 4 | (141 | ) | 6 | ||||||||
| Amounts reclassified to income, net of taxes of $1, $125 and $52 | 2 | 232 | 96 | |||||||||
| 6 | 91 | 102 | ||||||||||
| Net unrealized gains (losses) on investments: | ||||||||||||
| Gains (losses) arising during the period, net of taxes of $(19), $2 and $(4) | (34 | ) | 4 | (7 | ) | |||||||
| Amounts reclassified to income, net of taxes of $-, $(2)and $- | — | (3 | ) | — | ||||||||
| (34 | ) | 1 | (7 | ) | ||||||||
| Comprehensive income | $ | 494 | $ | 1,069 | $ | 531 | ||||||
See Notes to Consolidated Financial Statements
76
DTE Energy Company
Notes to Consolidated Financial Statements
| Note 1
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Corporate Structure
DTE Energy owns the following businesses:
| • | Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in southeast Michigan; | ||
| • | MichCon, a natural gas utility engaged in the purchase, storage, transmission, distribution and sale | ||
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Detroit Edison and MichCon are regulated by the MPSC. The FERC regulates certain activities of Detroit Edison’s business as well as various other aspects of businesses under DTE Energy. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and MDEQ.
References in this report to “Company” or “DTE” are to DTE Energy and its subsidiaries, collectively.
| Net | Net | Accumulated | ||||||||||||||
| Unrealized | Unrealized | Other | ||||||||||||||
| Losses on | Gains on | Benefit | Comprehensive | |||||||||||||
| (in Millions) | Derivatives | Investments | Obligations | Loss | ||||||||||||
| Beginning balances | $ | (104 | ) | $ | 15 | $ | (122 | ) | $ | (211 | ) | |||||
| Current period change | 91 | 1 | 6 | 98 | ||||||||||||
| Ending balance | $ | (13 | ) | $ | 16 | $ | (116 | ) | $ | (113 | ) | |||||
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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.
For entities that are considered variable interest entities, the Company applies the provisions of FIN 46(R),Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.We consolidate variable interest entities(VIEs) for which we are the primary beneficiary in accordance with FIN 46(R). In general, we determine whether we are the primary beneficiary of a VIE through a qualitative analysis of risk which indentifies which variable interest holder absorbs the majority of the financial risk or rewards and variability of the VIE. In performing this analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the identification of variable interest holders including equity owners, customers, suppliers and debt holders and which parties participated significantly in the design of the entity. If the qualitative analysis is inconclusive, a specific quantitative analysis is performed in accordance with FIN 46(R).
Legal entities within the Company’s Power and Industrial Projects segments enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are designed to pass-through the commodity risk associated with these contracts to the customers, with the
77
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Company retaining operational and customer default risk and generally are VIEs. These arrangements are assessed on a qualitative and, if necessary, quantitative basis, in accordance with the requirements of FIN 46(R) to determine who is the primary beneficiary. If the Company is the primary beneficiary, the VIE is consolidated. If the Company is not the primary beneficiary, the VIE is accounted for under the equity method of accounting. The VIEs are reviewed for reconsideration events each quarter, and the assessment of the primary beneficiary updated, if necessary.
DTE Energy has interests in various unconsolidated trusts that were formed for 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. We have reviewed these interests in accordance with FIN 46(R) and have determined they are VIEs, but the Company is not the primary beneficiary.
The maximum risk exposure for consolidated VIEs is reflected on our Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally the extent of our investment.
The following table summarizes the amounts for the Company’s variable interest entities as of December 31, 2008 and 2007:
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
Variable Interest Entities — Consolidated | ||||||||
| Total Assets | $ | 47 | $ | 113 | ||||
| Total Liabilities | 39 | 81 | ||||||
| Shareholders’ Equity | (4 | ) | 51 | |||||
Variable Interest Entities — Non-consolidated | ||||||||
| Other Investments | $ | 191 | $ | 54 | ||||
| Trust preferred — linked securities | 289 | 289 | ||||||
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 electric and gas provided but unbilled at the end of each month.
Detroit Edison’s accrued revenues include a component for the cost of power sold that is recoverable through the PSCR mechanism. MichCon’s accrued revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism. Annual PSCR and GCR proceedings before the MPSC permit Detroit Edison and MichCon to recover prudent and reasonable supply costs. Any overcollection or undercollection of costs, including interest, will be reflected in future rates. See Note 5.
Non-utility businesses recognize revenues as services are provided and products are delivered. Trading activities are accounted for under the provisions of EITF IssueNo. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activites”, which requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the Consolidated Statement of Operations. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses in operating revenues.
78
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Comprehensive Income
Comprehensive income is the change in common 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 other comprehensive income for the year ended December 31, 2008 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, and changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, pursuant to SFAS No. 158, and foreign currency translation adjustments.
| Net | Net | Accumulated | ||||||||||||||||||
| Unrealized | Unrealized | Other | ||||||||||||||||||
| Gains on | Losses on | Benefit | Foreign Currency | Comprehensive | ||||||||||||||||
| Derivatives | Investments | Obligations | Translation | Loss | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Beginning balances | $ | (13 | ) | $ | 16 | $ | (116 | ) | $ | — | $ | (113 | ) | |||||||
| Current period change | 6 | (34 | ) | (22 | ) | (2 | ) | (52 | ) | |||||||||||
| Ending balance | $ | (7 | ) | $ | (18 | ) | $ | (138 | ) | $ | (2 | ) | $ | (165 | ) | |||||
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 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. Customer accounts are written off based upon approved regulatory and legislative requirements.
The allowance for doubtful accounts for our two utilities is 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 time the next bill is issued, typically monthly, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on contractual past-due terms established with customers.
For our Energy Trading, non-regulated segment, the customer allowance for doubtful accounts is calculated based on specific review of probable future collectibles based on receivable balances in excess of 90 days.
Unbilled revenues of $812 million and $843 million are included in customer accounts receivable at December 31, 2008 and 2007, respectively.
Inventories
The Company values fuel inventory, including gas inventory in the Energy Trading segment, and materials and supplies at average cost.
Gas inventory at MichCon is determined using thelast-in, first-out (LIFO) method. At December 31, 2008, the replacement cost of gas remaining in storage exceeded the $14 million LIFO cost by $232 million. During 2008, MichCon liquidated 4.2 billion cubic feet of prior years’ LIFO layers. The liquidation reduced
79
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
2008 cost of gas by approximately $21 million, but had no impact on earnings as a result of the GCR mechanism. At December 31, 2007, the replacement cost of gas remaining in storage exceeded the $32 million LIFO cost by $288 million. During 2007, MichCon liquidated 9.5 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2007 cost of gas by approximately $30 million, but had no impact on earnings as a result of the GCR mechanism.
Property, Retirement and Maintenance, and Depreciation and Depletion
Summary of property by classification as of December 31:
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
Property, Plant and Equipment | ||||||||
| Electric Utility | ||||||||
| Generation | $ | 8,544 | $ | 8,100 | ||||
| Distribution | 6,433 | 6,272 | ||||||
| Total Electric Utility | 14,977 | 14,372 | ||||||
| Gas Utility | ||||||||
| Distribution | 2,327 | 2,392 | ||||||
| Storage | 378 | 273 | ||||||
| Other | 1,090 | 953 | ||||||
| Total Gas Utility | 3,795 | 3,618 | ||||||
| Non-utility and other | 1,293 | 1,423 | ||||||
| Assets held for sale | — | (604 | ) | |||||
| Total Property, Plant and Equipment | 20,065 | 18,809 | ||||||
Less Accumulated Depreciation and Depletion | ||||||||
| Electric Utility | ||||||||
| Generation | (3,690 | ) | (3,539 | ) | ||||
| Distribution | (2,138 | ) | (2,101 | ) | ||||
| Total Electric Utility | (5,828 | ) | (5,640 | ) | ||||
| Gas Utility | ||||||||
| Distribution | (955 | ) | (970 | ) | ||||
| Storage | (107 | ) | (100 | ) | ||||
| Other | (603 | ) | (538 | ) | ||||
| Total Gas Utility | (1,665 | ) | (1,608 | ) | ||||
| Non-utility and other | (341 | ) | (350 | ) | ||||
| Assets held for sale | — | 197 | ||||||
| Total Accumulated Depreciation and Depletion | (7,834 | ) | (7,401 | ) | ||||
Net Property, Plant and Equipment | $ | 12,231 | $ | 11,408 | ||||
Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction (AFUDC). AFUDC capitalized during 2008 and 2007 was approximately $50 million and $32 million, respectively. The cost of properties retired, less salvage value, at Detroit Edison and MichCon is charged to accumulated depreciation.
80
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $25 million and $4 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2009 were accrued at December 31, 2008 and December 31, 2007, respectively. Amounts are being accrued on a pro-rata basis over an18-month period that began in November 2007. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC.
The Company bases depreciation provisions for utility property at Detroit Edison and MichCon on straight-line and units-of-production rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.3% in 2008, 2007 and 2006. The composite depreciation rate for MichCon was 3.2% in 2008, 3.1% in 2007 and 2.8% in 2006.
The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2008 follows:
| Estimated Useful Lives in Years | ||||||||||||
Utility | Generation | Distribution | Transmission | |||||||||
| Electric | 40 | 37 | N/A | |||||||||
| Gas | N/A | 40 | 38 | |||||||||
Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods. The estimated useful lives for major classes of non-utility assets and facilities ranges from 5 to 50 years.
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.
Intangible assets relating to capitalized software are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation and depletion 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 intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 15 years. Intangible assets amortization expense was $54 million in 2008, $42 million in 2007 and $37 million in 2006. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2008 were $576 million and $192 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $493 million and $141 million, respectively. Amortization expense of intangible assets is estimated to be $54 million annually for 2009 through 2013.
Asset Retirement Obligations
| (in Millions) | 2007 | 2006 | ||||||
Property, Plant and Equipment | ||||||||
| Electric Utility | ||||||||
| Generation | $ | 8,100 | $ | 7,667 | ||||
| Distribution | 6,272 | 6,249 | ||||||
| Total Electric Utility | 14,372 | 13,916 | ||||||
| Gas Utility | ||||||||
| Distribution | 2,392 | 2,175 | ||||||
| Storage | 241 | 245 | ||||||
| Other | 985 | 985 | ||||||
| Total Gas Utility | 3,618 | 3,405 | ||||||
| Non-utility and other | 1,423 | 1,903 | ||||||
| Assets held for sale | (604 | ) | — | |||||
| Total Property, Plant and Equipment | 18,809 | 19,224 | ||||||
Less Accumulated Depreciation and Depletion | ||||||||
| Electric Utility | ||||||||
| Generation | (3,539 | ) | (3,410 | ) | ||||
| Distribution | (2,101 | ) | (2,170 | ) | ||||
| Total Electric Utility | (5,640 | ) | (5,580 | ) | ||||
| Gas Utility | ||||||||
| Distribution | (970 | ) | (926 | ) | ||||
| Storage | (100 | ) | (108 | ) | ||||
| Other | (538 | ) | (513 | ) | ||||
| Total Gas Utility | (1,608 | ) | (1,547 | ) | ||||
| Non-utility and other | (350 | ) | (646 | ) | ||||
| Assets held for sale | 197 | — | ||||||
| Total Accumulated Depreciation and Depletion | (7,401 | ) | (7,773 | ) | ||||
Net Property, Plant and Equipment | $ | 11,408 | $ | 11,451 | ||||
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| Estimated Useful Lives in Years | ||||||||||||
| Utility | Generation | Distribution | Transmission | |||||||||
| Electric | 40 | 37 | N/A | |||||||||
| Gas | N/A | 40 | 37 | |||||||||
The Company records asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligationsand FIN 47,Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. 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 for the synthetic fuel operations, gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at 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 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.
81
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
For the Company’s regulated operations, timing differences arise in the expense recognition of legal asset retirement costs that the Company is currently recovering in rates. The Company defers such differences under SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.
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.
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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 20072008 follows:
| (in Millions) | ||||||||
| Asset retirement obligations at January 1, 2007 | $ | 1,221 | ||||||
| (In millions) | ||||||||
| Asset retirement obligations at January 1, 2008 | $ | 1,293 | ||||||
| Accretion | 78 | 84 | ||||||
| Liabilities incurred | 4 | 2 | ||||||
| Liabilities settled | (21 | ) | (18 | ) | ||||
| Assets held for sale | (16 | ) | ||||||
| Transfers from Assets held for sale | 14 | |||||||
| Revision in estimated cash flows | 27 | (14 | ) | |||||
| Asset retirement obligations at December 31, 2007 | 1,293 | |||||||
| Asset retirement obligations at December 31, 2008 | 1,361 | |||||||
| Less amount included in current liabilities | (16 | ) | (21 | ) | ||||
| $ | 1,277 | $ | 1,340 | |||||
Approximately $1.1$1.2 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.
Unconventional Gas Production
The Company follows the successful efforts method of accounting for investments in 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 has found proved reserves. If an exploratory well has not found 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 unproved properties are expensed as incurred. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. 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 the units-of-production method.
Long-Lived Assets
The Company reviews its long-lived assets 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 costcosts to sell.
83
82
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Our Power and Industrial Projects segment has long-term contracts with General Motors Corporation (GM) and Ford Motor Company (Ford) to provide onsite energy services at certain of their facilities. At December 31, 2008, the book value oflong-lived assets used in the servicing of these facilities was approximately $85 million. In addition, we have an equity investment of approximately $40 million in an entity which provides similar services to Chrysler LLC (Chrysler). These companies are in financial distress, with GM and Chrysler recently receiving loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. We consider the recent announcements by these companies as an indication of possible impairment due to a significant adverse change in the business climate that could affect the value of our long-lived assets as described in SFAS 144, “Accounting for the Impairment or Disposal ofLong-Lived Assets” and have performed an impairment test on these assets. Based on our current undiscounted cash flow projections we have determined that we do not have an impairment as of December 31, 2008. We have also determined that we do not have an other than temporary decline in ourChrysler-related equity investment as described in APB 18, “The Equity Method of Accounting for Investments in Common Stock.” We will continue to assess these matters in future periods for possible asset impairments.
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, 20072008 and December 31, 20062007 is as follows:
| Total | ||||
| (In millions) | ||||
| Balance at December 31, 2006 | $ | 2,057 | ||
| Synthetic fuels impairment | (4 | ) | ||
| Sale of non-utility businesses and other | (16 | ) | ||
| Balance at December 31, 2007 | $ | 2,037 | ||
| Balance at December 31, 2008 | $ | 2,037 | ||
We performed our annual impairment test on October 1, 2008 and determined that the estimated fair value of our reporting units exceeded their carrying value and no impairment existed. During the fourth quarter of 2008, the closing price of DTE Energy’s stock declined by approximately 11% and at December 31, 2008 was approximately 3 percent below its book value per share. In assessing whether the recent modest decline in the trading price of DTE Energy’s common stock below its book value was an indication of impairment, we considered the following factors: (1) the relatively short duration and modest decline in the trading price of DTE Energy’s common stock; (2) the anticipated impact of the national and regional recession on DTE Energy’s future operating results and cash flows; (3) the favorable results of the recently performed annual impairment test and (4) a comparison of book value to the traded market price, including the impact of a control premium. As a result of this assessment, we determined that the decline in market price did not represent a triggering event at December 31, 2008 requiring an update to the October 1, 2008 impairment test. We will continue to assess these matters in future periods for possible impairments.
Intangible Assets
The Company has certain intangible assets relating to non-utility contracts and emission allowances. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. Intangible assets amortization expense was $7 million in 2008, $2 million in 2007 and $5 million in 20062006. The gross carrying amount and $2accumulated amortization of intangible assets at December 31, 2008
83
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
were $85 million in 2005.and $15 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $31 million and $6 million, respectively. The gross carrying amount and accumulated amortization ofOur intangible assets related to emission allowances increased to $19 million at December 31, 2006 were $802008 from $9 million and $8 million, respectively.at December 31, 2007. Net intangible assets reclassified to Assets held for sale totaled $38 million at December 31, 2007. Amortization expense of intangible assets is estimated to be $3$7 million annually for 20082009 through 2012.2013.
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 impact on the Consolidated Statements of Operations.
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.
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Investments in Debt and Equity Securities
The Company generally classifies investments in debt and equity securities as either trading or available-for-sale and has recorded such investments at market value with unrealized gains or losses included in earnings 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 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 investment being written down to its estimated fair value. See Note 6.15.
84
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Consolidated Statement of Cash Flows
A detailed analysis of the changes in assets and liabilities that are reported in the Consolidated Statement of Cash Flows follows:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately | ||||||||||||||||||||||||
| Accounts receivable, net | $ | (102 | ) | $ | 441 | $ | (633 | ) | $ | 328 | $ | (163 | ) | $ | 385 | |||||||||
| Accrued GCR revenue | (10 | ) | 120 | (16 | ) | (71 | ) | (10 | ) | 120 | ||||||||||||||
| Inventories | 80 | (49 | ) | (6 | ) | 96 | 80 | (49 | ) | |||||||||||||||
| Recoverable pension and postretirement costs | 738 | (1,184 | ) | 61 | (1,324 | ) | 738 | (1,184 | ) | |||||||||||||||
| Accrued/prepaid pensions | (401 | ) | 218 | 17 | 944 | (401 | ) | 218 | ||||||||||||||||
| Accounts payable | 6 | (68 | ) | 290 | (286 | ) | 5 | (10 | ) | |||||||||||||||
| Accrued PSCR refund | 41 | (101 | ) | (127 | ) | 82 | 41 | (101 | ) | |||||||||||||||
| Income taxes payable | (19 | ) | 46 | (38 | ) | (22 | ) | (19 | ) | 46 | ||||||||||||||
| Risk management and trading activities | 160 | (518 | ) | 353 | ||||||||||||||||||||
| Derivative assets and liabilities | (178 | ) | 222 | (520 | ) | |||||||||||||||||||
| Postretirement obligation | (320 | ) | 1,008 | 132 | 340 | (320 | ) | 1,008 | ||||||||||||||||
| Other assets | (430 | ) | (134 | ) | (9 | ) | (51 | ) | (430 | ) | (134 | ) | ||||||||||||
| Other liabilities | 453 | 229 | (102 | ) | 55 | 453 | 229 | |||||||||||||||||
| $ | 196 | $ | 8 | $ | (78 | ) | $ | (87 | ) | $ | 196 | $ | 8 | |||||||||||
Supplementary cash and non-cash information for the years ended December 31, were as follows:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Cash paid for: | ||||||||||||
| Interest (net of interest capitalized) | $ | 537 | $ | 526 | $ | 516 | ||||||
| Income taxes | $ | 326 | $ | 89 | $ | 80 | ||||||
| Noncash investing and financing activities | ||||||||||||
| Notes received from sale of synfuel projects | $ | — | $ | — | $ | 20 | ||||||
| Sale of assets | ||||||||||||
| Note receivable | $ | — | $ | — | $ | 47 | ||||||
| Other assets | $ | — | $ | — | $ | 45 | ||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Cash paid (received) for: | ||||||||||||
| Interest (net of interest capitalized) | $ | 496 | $ | 537 | $ | 526 | ||||||
| Income taxes | $ | (59 | ) | $ | 326 | $ | 89 | |||||
In conjunctionconnection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent; therefore,agent. As a result, the Company entered into a demand financing agreement for up to $150$50 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). The amounts outstanding under this facility were $13$26 million and $23$13 million at December 31, 2008 and 2007, and 2006, respectively.
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| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Electric utility | $ | 8 | $ | (6 | ) | $ | (26 | ) | ||||
| Non-utility: | ||||||||||||
| Barnett shale | 27 | (4 | ) | — | ||||||||
| Waste coal recovery | — | 19 | — | |||||||||
| Landfill gas recovery | — | 14 | — | |||||||||
| Power generation | — | 42 | — | |||||||||
| 27 | 71 | — | ||||||||||
| Other | 2 | 2 | 3 | |||||||||
| $ | 37 | $ | 67 | $ | (23 | ) | ||||||
See the following notes for other accounting policies impacting the Company’s consolidated financial statements:
Note | Title | |||
| 2 | New Accounting Pronouncements | |||
| 5 | Regulatory Matters | |||
| 8 | Income Taxes | |||
| 15 | Fair Value | |||
| 16 | Financial and Other Derivative Instruments | |||
| Retirement Benefits and Trusteed Assets | ||||
| Stock-based Compensation | ||||
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Notes to Consolidated Financial Statements — NEW ACCOUNTING PRONOUNCEMENTS(Continued)
| NOTE 2 — | NEW ACCOUNTING PRONOUNCEMENTS |
Fair Value Accounting
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. TheEffective January 1, 2008, the Company adopted SFAS No. 157 effective January 1, 2008. The157. As permitted by FASB deferredStaff PositionFAS No. 157-2, the Company has elected to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The cumulative effect adjustment upon adoption of SFAS No. 157 will not haverepresented a material impact$4 million increase to the January 1, 2008 balance of retained earnings. See also Note 15.
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This standardStatement permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items, for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to
86
entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The adoption of SFAS No. 159 is not expected to have a material impact to the Company’s financial statements. At January 1, 2008, the Company haselected not elected to use the fair value option for financial assets and liabilities held at that date.
In October 2008, the FASB issued FASB Staff Position (FSP)157-3,Determining the Fair Value of a Financial Asset in a Market That is Not Active. The FSP clarifies the application of SFAS No. 157,Fair Value Measurements,in an inactive market, and provides an illustrative example to demonstrate how the fair value of a financial asset is determined when the market for that financial asset is inactive. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of the FSP did not have a material impact on the Company’s consolidated financial statements.
Business Combinations
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations,to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish this, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is applied prospectively to business combinations entered into by the Company after January 1, 2009, with earlier adoption prohibited. The Company will apply the requirements of SFAS No. 141(R) to business combinations consummated after January 1, 2009.
GAAP Hierarchy
In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles.This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements under GAAP. SFAS No. 162 is effective 60 days following the approval of the Public Company Accounting Oversight Board amendments to AU section 411,The Meaning of Present Fairly
86
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
in Conformity with Generally Accepted Accounting Principles. The Company will adopt SFAS No. 162 once effective. The adoption is not expected to have a material impact on its consolidated financial statements.
Useful Life of Intangible Assets
In May 2008, the FASB issuedFSP 142-3,Determination of the Useful Life of Intangible Assets.This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142,Goodwill and Other Intangible Assets. For a recognized intangible asset, an entity shall disclose information that enables users to assess the extent to which the expected future cash flows associated with the asset are affected by the entity’s intentand/or ability to renew or extend the arrangement. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. The FSP will not have a material impact on the Company’s consolidated financial statements.
Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities
In June 2008, the FASB issued FSPEITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128,Earnings Per Share.Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. Stock awards granted by the Company under its stock-based compensation plan qualify as a participating security. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and will be applied retrospectively. Adoption of this FSP is expected to result in a reduction of Basic and Diluted EPS of $0.02 and $0.01 or less, respectively. See Note 10 for further disclosure.
Disclosures about Derivative Instruments and Guarantees
In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This Statement requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company will adopt SFAS No. 161 on January 1, 2009.
In September 2008, the FASB issued FSPNo. 133-1 andFIN 45-4,Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161.This FSP is intended to improve disclosures about credit derivatives by requiring more information about the potential adverse effects of changes in credit risk on the financial position, financial performance, and cash flows of the sellers of credit derivatives. This FSP also requires additional disclosures about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN 45 are effective for reporting periods ending after November 15, 2008. The FSP also clarifies that the disclosures required by SFAS No. 161 should be provided for any reporting period (annual or interim) beginning after November 15, 2008. The Company has adopted these pronouncements as of December 31, 2008. See Note 16 for further disclosures.
87
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51.This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements which shall be applied retrospectively for all periods presented. The Company will adopt SFAS No. 160 as of January 1, 2009. Adoption of SFAS No. 160 will not have a material effect on the Company’s consolidated financial statements.
Offsetting Amounts Related to Certain Contracts
In April 2007, the FASB issued FSPFIN 39-1,Amendment of FASB Interpretation No. 39. This standard will permitFSP permits the Company to offset 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 arrangement. As a result, the Company will beis permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007. It is applied retrospectively by adjusting the financial statements for all periods presented. The Company presently records the net fair valueadopted FSPFIN 39-1 as of derivative assets and liabilities for those contracts held by Energy Trading that are subject to master netting arrangements, and separately records amounts for cash collateral received or paid for these instruments. Under this standard, ifJanuary 1, 2008. At adoption, the Company chooseschose to offset the collateral amounts against the fair value of derivative assets and liabilities, reducing both the Company’s total assets and total liabilities. The Company retrospectively reclassified certain assets and liabilities could be reduced. on the Consolidated Statement of Financial Position at December 31, 2007 as follows:
| As Previously | FSP FIN 39-1 | |||||||||||
| Reported | Adjustments | As Adjusted | ||||||||||
| (In millions) | ||||||||||||
Current Assets | ||||||||||||
| Accounts receivable-other | $ | 504 | $ | 10 | $ | 514 | ||||||
| Derivative assets | 195 | (14 | ) | 181 | ||||||||
Other Assets | ||||||||||||
| Derivative assets | 207 | (8 | ) | 199 | ||||||||
Current Liabilities | ||||||||||||
| Accounts payable | 1,198 | (9 | ) | 1,189 | ||||||||
| Derivative liabilities | 282 | (1 | ) | 281 | ||||||||
Other Liabilities | ||||||||||||
| Derivative liabilities | 452 | (2 | ) | 450 | ||||||||
The guidancetotal cash collateral received, net of cash collateral posted was $30 million at December 31, 2008. In accordance with FSP FIN 39-1, derivative assets and derivative liabilities are shown net of collateral of $31 million and $17 million, respectively. At December 31, 2008, amounts not related to unrealized derivative positions totaling $7 million and $23 million were included in this FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. accounts receivable and accounts payable, respectively.
Disclosures about Transfers of Financial Assets and Interests in Variable Interest Entities
In December 2008, the FASB issued FASB Staff Position (FSP)FAS 140-4 and FIN 46(R)-8,Disclosures about Transfers of Financial Assets and Interest in Variable Interest Entities.The purpose of the FSP is to be applied retrospectivelypromptly improve disclosures by adjustingpublic entities and enterprises until the financial statementspending amendments to FASB Statement No. 140,Accounting for all periods presented. The company adopted the FSP asTransfers and Servicing of January 1, 2008.
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88
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, are finalized and approved by the Board. Effective for reporting periods ending after December 15, 2008, the FSP amends Statement 140 to require public entities to provide additional disclosures about transfers of financial assets and variable interests in qualifying special-purpose entities. It also amends FIN 46(R) to require public enterprises to provide additional disclosures about their involvement with variable interest entities. The adoption of this FSP did not have a material impact on the Company’s consolidated financial statements. See Note 1.
Employers’ Disclosures about Postretirement Benefit Plan Assets
On December 30, 2008, the FASB issued FASB Staff Position (FSP) FAS 132(R)-1,Employers’ Disclosures about Postretirement Benefit Plan Assets.This FSP amends SFAS No. 160 is132 (revised 2003),Employers’ Disclosures about Pensions and Other Postretirement Benefits,to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The disclosure requirements required by this FSP are effective for fiscal years and interim periods within those fiscal years, beginning on orending after December 15, 2008. Earlier adoption is prohibited. This Statement shall be applied prospectively as of the beginning of the fiscal year in which this Statement is initially applied, except for the presentation and disclosure requirements. The presentation and disclosure requirements shall be applied retrospectively for all periods presented.2009. The Company is currently assessing the effects ofwill adopt this statement, and has not yet determined its impactFSP on its consolidated financial statements.December 31, 2009.
| NOTE 3 — | DISPOSALS AND DISCONTINUED OPERATIONS |
Sale of Antrim Shale Gas Exploration and Production Business
In 2007, the Company sold its Antrim shale gas exploration and production business (Antrim) for gross proceeds of $1.262$1.3 billion. The pre-tax gain recognized on this sale amounted to $900 million ($580 million after-tax) and is reported on the Consolidated Statements of Operations under the line item, “Gain on sale of non-utility business,” and included in the Corporate & Other segment. Prior to the sale, the operating results of Antrim were reflected in the Unconventional Gas Production segment.
The Antrim business is not presented as a discontinued operation due to continuation of cash flows related to the sale of a portion of Antrim’s natural gas production to Energy Trading under the terms of natural gas sales contracts that expire in 2010 and 2012. These continuing cash flows, while not significant to DTE Energy, are significant to Antrim and therefore meet the definition of continuing cash flows as described inEITF 03-13,Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations.
Prior to the sale, a substantial portion of the Company’s price risk related to expected gas production from its Antrim shale business had been hedged through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. The contracts were retained and assigned to Energy Trading, and offsetting financial contracts were put into place to effectively settle these positions. As a result of these transactions and market research performed by the Company, we gained additional insight and visibility into the value ascribed to these contracts by third party market participants, including contract periods that extend beyond the actively traded period. In conjunction with the Antrim sale, and effective settlement of these contract positions, the Company reclassified amounts held in accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in 2007 by $323 million.
Plan to Sell Interest in Certain Power and Industrial Projects
During the third quarter of 2007, the Company expectsannounced its plans to sell a 50 percent50% interest in a portfolio of select Power and Industrial Projects (Projects). In addition to the proceeds that the Company will receive from the sale of the 50 percent equity interest, the company that will own the Projects will obtain debt financing and the proceeds will be distributed to DTE Energy immediately prior to the sale of the equity interest. The Company expects to complete the transaction in the first half of 2008. This timing, however, is highly dependent on availability of acceptable financing terms in the credit markets.Projects. As a result, the Company cannot predict the timing with certainty. The Company expects to recognize a gain upon completionassets and liabilities of the transaction. In conjunction with the sale, the Company will enter into a management services agreement to manage the day-to-day operations of the Projects and to act as the managing member of the company that owns the Projects. We
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89
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Consolidated Statements of Operations. Financial Position included $28 million of minority interests in the Projects classified as held for sale as of December 31, 2007.
The following table presents the major classes of assets and liabilities of the Projects classified as held for sale at December 31, 2007:
| (in Millions) | ||||||||
| (In millions) | ||||||||
| Cash and cash equivalents | $ | 11 | $ | 11 | ||||
| Accounts receivable (less allowance for doubtful accounts of $4) | 65 | 65 | ||||||
| Inventories | 4 | 4 | ||||||
| Other current assets | 3 | 3 | ||||||
| Total current assets held for sale | 83 | 83 | ||||||
| Investments | 55 | 55 | ||||||
| Property, plant and equipment, net of accumulated depreciation of $183 | 285 | 285 | ||||||
| Intangible assets | 38 | 38 | ||||||
| Long-term notes receivable | 46 | 46 | ||||||
| Other noncurrent assets | 1 | 1 | ||||||
| Total noncurrent assets held for sale | 425 | 425 | ||||||
| Total assets held for sale | $ | 508 | $ | 508 | ||||
| Accounts payable | $ | 38 | $ | 38 | ||||
| Other current liabilities | 10 | 10 | ||||||
| Total current liabilities associated with assets held for sale | 48 | 48 | ||||||
| Long-term debt (including capital lease obligations of $31) | 53 | 53 | ||||||
| Asset retirement obligations | 16 | 16 | ||||||
| Other liabilities | 13 | 13 | ||||||
| Total noncurrent liabilities associated with assets held for sale | 82 | 82 | ||||||
| Total liabilities related to assets held for sale | $ | 130 | $ | 130 | ||||
Sale of Interest in Barnett Shale Properties
In 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $250 million, subject to post-closing adjustments. The properties in the sale include 186 billion cubic feet of proved and probable reserves on 11,000 net acres in the core area of the Barnett shale.$260 million. As of December 31, 2007, property, plant and equipment of approximately $122 million, net of approximately $14 million of accumulated depreciation and depletion, was classified as held for sale. The Company expects to recognizerecognized a gain upon completion of $128 million ($81 million after-tax) on the transaction.sale during 2008.
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Synthetic Fuel Business
The Company discontinued the operations of ourits synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. Through December 31, 2007, the Company hasThe synthetic fuel business generated and recorded approximately $601 million inoperating losses that were substantially offset by production tax credits.
The Company has 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
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Company estimates that its maximum potential liability under these guarantees at December 31, 20072008 is $3.1$2.9 billion. At December 31, 2007, the Company has reserved $436 million of its maximum potential liability, primarily representing the estimated refund of certain payments made by its synfuel partners.
As shown in the following table, the Company has reported the business activity of the Synthetic Fuelsynthetic fuel business as a discontinued operation. The amounts exclude general corporate overhead costs:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Operating Revenues | $ | 1,069 | $ | 863 | $ | 927 | $ | 7 | $ | 1,069 | $ | 863 | ||||||||||||
| Operation and Maintenance | 1,265 | 1,019 | 1,167 | 9 | 1,265 | 1,019 | ||||||||||||||||||
| Depreciation and Amortization | (6 | ) | 24 | 58 | (2 | ) | (6 | ) | 24 | |||||||||||||||
| Taxes other than Income | 5 | 12 | 20 | (1 | ) | 5 | 12 | |||||||||||||||||
| Asset (Gains) and Losses, Reserves and Impairments, Net (1) | (280 | ) | 40 | (367 | ) | |||||||||||||||||||
| Asset (Gains) and Losses, Reserves and Impairments, Net(1) | (31 | ) | (280 | ) | 40 | |||||||||||||||||||
| Operating Income (Loss) | 85 | (232 | ) | 49 | 32 | 85 | (232 | ) | ||||||||||||||||
| Other (Income) and Deductions | (9 | ) | (20 | ) | (34 | ) | (2 | ) | (9 | ) | (20 | ) | ||||||||||||
| Minority Interest | (188 | ) | (251 | ) | (318 | ) | 2 | (188 | ) | (251 | ) | |||||||||||||
| Income Taxes | ||||||||||||||||||||||||
| Provision | 98 | 14 | 139 | 13 | 98 | 14 | ||||||||||||||||||
| Production Tax Credits | (21 | ) | (23 | ) | (43 | ) | (1 | ) | (21 | ) | (23 | ) | ||||||||||||
| 77 | (9 | ) | 96 | 12 | 77 | (9 | ) | |||||||||||||||||
| Net Income (1) | $ | 205 | $ | 48 | $ | 305 | ||||||||||||||||||
| Net Income(1) | $ | 20 | $ | 205 | $ | 48 | ||||||||||||||||||
| (1) | Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007. |
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| Year Ended December 31 | ||||||||||||
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Revenues (1) | $ | — | $ | 1 | $ | 1 | ||||||
| Expenses | — | 3 | 2 | |||||||||
| Loss before income taxes | — | (2 | ) | (1 | ) | |||||||
| Income tax benefit | — | — | — | |||||||||
| Loss from discontinued operations | $ | — | $ | (2 | ) | $ | (1 | ) | ||||
| Year Ended December 31 | ||||||||||||
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Revenues (1) | $ | — | $ | 1 | $ | 18 | ||||||
| Expenses | — | 6 | 67 | |||||||||
| Loss before income taxes | — | (5 | ) | (49 | ) | |||||||
| Income tax benefit | — | (2 | ) | (14 | ) | |||||||
| Loss from discontinued operations | $ | — | $ | (3 | ) | $ | (35 | ) | ||||
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Landfill Gas Recovery
In 2006, the Company’s Power and Industrial Projects segment recorded a pre-tax impairment loss of $14 million at its landfill gas recovery unit relating to the write down of assets at several landfill sites. The fixed assets were impaired due to continued operating losses and the oil price-related phase-out of production tax credits. The impairment was recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of certain assets was not recoverable. The Company determined the fair value of the assets utilizing a discounted cash flow technique.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Non-Utility Power Generation
In 2006, the Power and Industrial Projects segment recorded a pre-tax impairment loss totaling $74 million for its investments in two natural gas-fired electric generating plants.
A loss of $42 million related to a 100% owned plant is recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations. The generating plant was impaired due to continued operating losses and the September 2006 delisting by MISO, resulting in the plant no longer providing capacity for the power grid. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the plant, which indicated that the carrying amount of the plant was not recoverable. The Company determined the fair value of the plant utilizing a discounted cash flow technique.
A loss of $32 million related to a 50% equity interest in Cretea gas-fired peaking electric generating plant is recorded within the Other (income) and deductions, Other expenses line in the Consolidated Statements of Operations for 2006.Operations. The investment was impaired due to continued operating losses and the expected sale of the investment. The Company determined the fair value of the plant utilizing a discounted cash flow technique, which indicated that the carrying amount of the investment exceeded its fair value.
Waste Coal Recovery
In 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss of $19 million related to its investment in proprietary technology used to refine waste coal. The fixed assets at our development operation were impaired due to continued operating losses and negative cash flow. In addition, the Company impaired all of its patents related to waste coal technology. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of the assets was not recoverable. The Company determined the fair value of the assets utilizing a discounted cash flow technique. The impairment loss was recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations.
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Restructuring — Performance Excellence ProcessCosts
In mid-2005,2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. Specifically, the Company began a series of focused improvement initiatives within Detroit Edison and MichCon, and associated corporate support functions. The Company expects this processincurred costs to continue into 2008.
Note 5.92
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statements of Operations. Deferred amounts are recorded in the Regulatory asset line on the Consolidated Statements of Financial Position. Costs incurred in 2008, 2007 and 2006 are as follows:
| Employee Severance Costs | Other Costs | Total Cost | Employee | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in Millions) | 2007 | 2006 | 2007 | 2006 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Severance Costs | Other Costs | Total Cost | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Costs incurred: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric Utility | $ | 15 | $ | 51 | $ | 50 | $ | 56 | $ | 65 | $ | 107 | $ | — | $ | 15 | $ | 51 | $ | 26 | $ | 50 | $ | 56 | $ | 26 | $ | 65 | $ | 107 | ||||||||||||||||||||||||||||||
| Gas Utility | 3 | 17 | 6 | 7 | 9 | 24 | — | 3 | 17 | 7 | 6 | 7 | 7 | 9 | 24 | |||||||||||||||||||||||||||||||||||||||||||||
| Other | 1 | 2 | 1 | 1 | 2 | 3 | — | 1 | 2 | 3 | 1 | 1 | 3 | 2 | 3 | |||||||||||||||||||||||||||||||||||||||||||||
| Total costs | 19 | 70 | 57 | 64 | 76 | 134 | — | 19 | 70 | 36 | 57 | 64 | 36 | 76 | 134 | |||||||||||||||||||||||||||||||||||||||||||||
| Less amounts deferred or capitalized: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric Utility | 15 | 51 | 50 | 56 | 65 | 107 | — | 15 | 51 | 26 | 50 | 56 | 26 | 65 | 107 | |||||||||||||||||||||||||||||||||||||||||||||
| Amount expensed | $ | 4 | $ | 19 | $ | 7 | $ | 8 | $ | 11 | $ | 27 | $ | — | $ | 4 | $ | 19 | $ | 10 | 7 | $ | 8 | $ | 10 | $ | 11 | $ | 27 | |||||||||||||||||||||||||||||||
| NOTE 5 — | REGULATORY MATTERS |
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.
Regulatory Assets and Liabilities
Detroit Edison and MichCon apply the provisions of SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,to their regulated operations. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 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 Company discontinuing the application of SFAS No. 71 for some or all of its utility businesses and may require the write-off of
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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 application of SFAS No. 71 to Detroit Edison and MichCon.
93
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The following are balances and a brief description of the regulatory assets and liabilities at December 31:
| (in Millions) | 2007 | 2006 | ||||||||||||||
| 2008 | 2007 | |||||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Securitized regulatory assets | $ | 1,124 | $ | 1,235 | $ | 1,001 | $ | 1,124 | ||||||||
| Recoverable income taxes related to securitized regulatory assets | $ | 616 | $ | 677 | $ | 549 | $ | 616 | ||||||||
| Recoverable pension and postretirement costs | 991 | 1,728 | ||||||||||||||
| Pension | 1,505 | 495 | ||||||||||||||
| Postretirement costs | 787 | 496 | ||||||||||||||
| Asset retirement obligation | 266 | 236 | 452 | 266 | ||||||||||||
| Other recoverable income taxes | 94 | 100 | 89 | 94 | ||||||||||||
| Recoverable costs under PA 141 | ||||||||||||||||
| Excess capital expenditures | 11 | 22 | 4 | 11 | ||||||||||||
| Deferred Clean Air Act expenditures | 28 | 67 | 10 | 28 | ||||||||||||
| Midwest Independent System Operator charges | 23 | 48 | 8 | 23 | ||||||||||||
| Electric Customer Choice implementation costs | 58 | 78 | 37 | 58 | ||||||||||||
| Enhanced security costs | 10 | 13 | 6 | 10 | ||||||||||||
| Unamortized loss on reacquired debt | 67 | 69 | 73 | 67 | ||||||||||||
| Deferred environmental costs | 41 | 40 | 43 | 41 | ||||||||||||
| Accrued PSCR/GCR revenue | 76 | 117 | 22 | 76 | ||||||||||||
| Recoverable uncollectibles expense | 42 | 45 | 122 | 42 | ||||||||||||
| Cost to achieve Performance Excellence Process | 146 | 102 | 154 | 146 | ||||||||||||
| Enterprise Business Systems costs | 26 | 9 | 26 | 26 | ||||||||||||
| Deferred income taxes — Michigan Business Tax | 364 | — | 394 | 364 | ||||||||||||
| Other | 3 | 3 | 2 | 3 | ||||||||||||
| 2,862 | 3,354 | 4,283 | 2,862 | |||||||||||||
| Less amount included in current assets | (76 | ) | (128 | ) | (52 | ) | (76 | ) | ||||||||
| $ | 2,786 | $ | 3,226 | $ | 4,231 | $ | 2,786 | |||||||||
Liabilities | ||||||||||||||||
| Asset removal costs | $ | 581 | $ | 576 | ||||||||||||
| Accrued pension | 115 | 72 | ||||||||||||||
| Safety and training cost refund | — | 3 | ||||||||||||||
| Accrued PSCR/GCR refund | 70 | 81 | ||||||||||||||
| Refundable income taxes | 104 | 114 | ||||||||||||||
| Fermi 2 refueling outage | 4 | 16 | ||||||||||||||
| Deferred income taxes — Michigan Business Tax | 364 | — | ||||||||||||||
| Other | 5 | 2 | ||||||||||||||
| 1,243 | 864 | |||||||||||||||
| Less amount included in current liabilities | (75 | ) | (99 | ) | ||||||||||||
| $ | 1,168 | $ | 765 | |||||||||||||
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Notes to Consolidated Financial Statements — (Continued)
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
Liabilities | ||||||||
| Asset removal costs | $ | 534 | $ | 581 | ||||
| Accrued pension | ||||||||
| Pension equalization mechanism | 72 | 44 | ||||||
| Negative pension offset | 110 | 71 | ||||||
| Accrued PSCR/GCR refund | 11 | 70 | ||||||
| Refundable costs under PA 141 | 16 | — | ||||||
| Refundable income taxes | 93 | 104 | ||||||
| Fermi 2 refueling outage | 25 | 4 | ||||||
| Deferred income taxes — Michigan Business Tax | 388 | 364 | ||||||
| Other | 5 | 5 | ||||||
| 1,254 | 1,243 | |||||||
| Less amount included in current liabilities | (52 | ) | (75 | ) | ||||
| $ | 1,202 | $ | 1,168 | |||||
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
| • | 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. | |
| • | 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. | |
| • | Recoverable pension and postretirement costs— In 2007, the Company adopted SFAS No. 158 which required, 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. The Company received approval from the MPSC to record the charge related to the additional liability as a regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement |
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| • | Asset retirement obligation— Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 and FIN 47. These obligations are primarily for Fermi 2 decommissioning |
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| • | Other recoverable income taxes— Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates. This asset will reverse over the remaining life of the related plant. (1) | |
| • | Excess capital expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense. | |
| • | Deferred Clean Air Act expenditures— PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures. | |
| • | Midwest Independent System Operator charges— PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator. | |
| • | Electric Customer Choice implementation costs— PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program. | |
| • | Enhanced security costs — | |
| • | 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. | |
| • | Deferred environmental costs— The MPSC approved the deferral and recovery of investigation and remediation costs associated with Gas Utility’s former MGP sites. This asset is offset in working capital by an environmental liability reserve. The amortization of the regulatory asset is not included in MichCon’s current rates because it is offset by the recognition of insurance proceeds. MichCon will request recovery of the remaining asset balance in future rate filings after the recognition of insurance proceeds is complete. (1) | |
| • | 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. | |
| • | Recoverable uncollectibles expense— MichCon receivable for the MPSC approved uncollectible expensetrue-up mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization. | |
| • | 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 will be amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred. | |
| • | Enterprise Business Systems (EBS) costs— | |
| • | Deferred income taxes — Michigan Business Tax (MBT)- In July 2007, the 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 |
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Notes to Consolidated Financial Statements — (Continued)
| (1) | Regulatory assets not earning a return. |
LIABILITIES
| • | Asset removal costs— The amount collected from customers for the funding of future asset removal activities. | |
| • | ||
| • | ||
| • | Accrued PSCR refund— Payable 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. |
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| • | Accrued GCR | |
| • | Refundable costs under PA 141 —Detroit Edison’s 2007 Choice Incentive Mechanism (CIM) reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received in 2008 that exceed the regulatory asset balances are required to be refunded to the affected classes. | |
| • | 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. | |
| • | Fermi 2 refueling outage— Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization. | |
| • | Deferred income taxes — Michigan Business Tax —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 impacts of the deferred tax assets will be reflected in rates. |
MPSC Show Cause Order
In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reduced in 2007. Subsequently, Detroit Edison filed its response explaining why its rates should not be reduced in 2007. Theto this order and the MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
As part of the settlement agreement, a Choice Incentive Mechanism (CIM)CIM was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90 percent90% of its reduction in non-fuel revenue from full service customers, up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100 percent100% of the increase in non-fuel revenue to the unrecovered regulatory asset balance. Approximately $28 millionIn March 2008, Detroit Edison filed a reconciliation of its CIM for the year 2007. Detroit Edison’s annual Electric Choice sales for 2007 were 2,239 GWh which was creditedbelow the base level of sales of 3,200 GWh. Accordingly, the Company used the resulting additional non-fuel revenue to thereduce unrecovered regulatory asset balances related to the RARS mechanism. This reconciliation did not result in 2007.any rate increase.
In November 2008, a settlement was filed in the 2007 CIM reconciliation. In the settlement, the parties agreed that the Detroit Edison 2007 CIM reconciliation and allocation filing was correct. All RARS revenues received in 2008 that exceed the regulatory asset balances will be refunded to the affected customer classes, and the only remaining classes to be reconciled in the RARS reconciliation case are the Residential and Special Manufacturing Contract classes. On January 13, 2009, the MPSC issued an order approving the settlement agreement.
2007 Electric Rate Case Filing
Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. The filing withSupplements and updates were filed on August 31, 2007 and February 20, 2008.
On December 23, 2008, the MPSC requested a $123issued an order in Detroit Edison’s February 20, 2008 updated rate case filing. The MPSC approved an annual revenue increase of $84 million effective January 14, 2009 or 2.9 percent,2.0% average increase in Detroit Edison’s annual revenue requirement for 2008.2009. Included in the approved $84 million increase in revenues is a return on equity of 11% on an expected 49% equity and 51% debt capital structure.
Other key aspects of the MPSC order include the following:
| • | In order to more accurately reflect the actual cost of providing service to business customers, the MPSC adopted an immediate 39% phase out of the residential rate subsidy, with the remaining amount to be eliminated in equal installments over the next five years, every October 1. | |
| • | Accepted Detroit Edison’s proposal to reinstate and modify the tracking mechanism on Electric Choice sales (CIM) with a base level of 1,561 GWh. The modified mechanism will not have a cap on the amount recoverable. | |
| • | Accepted Detroit Edison’s proposal to terminate the Pension Equalization Mechanism. | |
| • | Approved an annual reconciliation mechanism to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $110 million and $51 million, respectively. | |
| • | Approved Detroit Edison’s proposal to recover a return on $15 million of costs in working capital associated with expenses associated with preparation of an application for a new nuclear generation facility at its current Fermi 2 site. |
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
2009 Electric Rate Case Filing
Detroit Edison filed a general rate case on January 26, 2009 based on a twelve months ended June 2008 historical test year. The filing with the MPSC requested a $378 million, or 8.1% average increase in Detroit Edison’s annual revenue requirement for the twelve months ended June 30, 2010 projected test year.
The requested $123$378 million increase in revenues is required in order to recover significantthe increased costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, customer uncollectible accounts, inflation, the capital costs of plant additions and inflationary increases, partially offset by net savings associated with the Performance Excellence Process. The filing was based on a return on equity of 11.25 percent on an expected 50 percent equity capital and 50 percent debt capital structure by year-end 2008.reduction in territory sales.
In addition, Detroit Edison’s filing makes,made, among other requests, the following proposals:
| • | |||
| • |
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| • | |||
| • | |||
| • |
In January 2009, Detroit Edison filed a supplementrequired application that included two new cost-based tariffs for schools, universities and community colleges. The filing is in compliance with Public Act 286 which required utilities to its April 2007file tariffs that ensure that eligible educational institutions are charged retail electric rates that reflect the actual cost of providing service to those customers. In February 2009, an MPSC order consolidated this proceeding with the January 26, 2009 electric rate case filing. A July 2007 decision by the Court of Appeals of the State of Michigan remanded back to the MPSC the November 2004 order in a prior Detroit Edison rate case that denied recovery of merger control premium costs. The supplemental filing addressed recovery of approximately $61 million related to the merger control premium. The filing also included the impact of the July 2007 enactment of the MBT, and other adjustments. The net impact of the supplemental changes results in an additional revenue requirement of approximately $76 million average increase in Detroit Edison’s annual revenue requirement for 2008.
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Accounting for Costs Related to Enterprise Business Systems (EBS)
In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of up to $60 million of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2007,2008, approximately $26 million of EBS costs have been deferred as a regulatory asset. In addition,the MPSC’s December 2008 order in the 2007 Detroit Edison rate case, the Commission approved the recovery of deferred EBS costs recorded as plant assets will be amortized over a 15-year10-year period pursuant to MPSC authorization.beginning in January 2009.
Fermi 2 Enhanced Security Costs Settlement
The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In December 2006, Detroit Edison filed an application with the MPSC for recovery of $11.4 million of Fermi 2 Enhanced Security Costs (ESC), discounted back to September 11, 2001 plus carrying costs from that date. In April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi 2 ESCEnhanced Security Costs (ESC) incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million plus carrying charges. A total of $13
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
$13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization ofexpense related to this regulatory asset was approximately $4 million and $3 million in 2007.for the years ended December 31, 2008, and 2007, respectively.
Reconciliation of Regulatory Asset Recovery Surcharge
In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing Regulatory Asset Recovery Surcharge (“RARS”).RARS. Thistrue-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS five-year5-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the five year5-year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write downwrite-down of RARS-related costs in 2007. As previously discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Approximately $11 million and $28 million was credited to the unrecovered regulatory asset balance during the years ended December 31, 2008 and 2007, respectively. The CIM expired in 2007 due to the CIM.April 2008.
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Power Supply CostsCost Recovery Proceedings
2005 Plan Year— In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval for recovery of an under-recoveryunder-collection of approximately $144 million at December 31, 2005 from its commercial and industrial customers. The filing included a motion for entry of an order to implement immediately a reconciliation surcharge of 4.96 mills per kWh on the bills of its commercial and industrial customers. The under-collected PSCR expense allocated to residential customers could not be recovered due to the PA 141 rate cap for residential customers, which expired January 1, 2006. In addition to the 2005 PSCR plan year reconciliation, the filing included a reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based uponon their contributions to pension expense during the subject periods. In September 2006, the MPSC ordered the Company to roll the entire 2004 PSCR over-collection amount to the Company’s 2005 PSCR Reconciliation. An order was issued on May 22, 2007 approving a 2005 PSCR undercollectionunder-collection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007. The surcharge will be reconciled in the Company’s 2008 PSCR reconciliation.
2006 Plan Year —In September 2005,March 2007, Detroit Edison filed its 2006 PSCR plan case seekingreconciliation that sought approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 mills per kWh above the amount included in base rates for commercial and industrial customers. Included in the factor for all customers are fuel and power supply costs, including transmission expenses, Midwest Independent Transmission System Operator (MISO) market participation costs, and NOx emission allowance costs. The Company’s PSCR Plan included a matrix which provided for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also included $97 million for recovery of its projected 2005 PSCRan under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requested MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and a fuel additive. In conjunction with DTE Energy’s sale of its transmission assets to ITC Transmission in February 2003, the FERC froze ITC Transmission’s rates through December 2004. In approving the sale, FERC authorized ITC Transmission’s recovery of the difference between the revenue it would have collected and the actual revenue collected during the rate freeze period. This amount is estimated to be $66 million which is to be included in ITC Transmission’s rates over a five-year period beginning June 1, 2006. This increased Detroit Edison’s transmission expense in 2006 by approximately $7 million. The MPSC authorized Detroit Edison in 2004 to recover transmission expenses through the PSCR mechanism.
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2007 Plan Year —In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company’s application included a request for an early hearing and temporary order granting such ratemaking authority. The Company’s 2007 PSCR plan includes fuel and power supply costs, including NOx and SO2 emission allowance costs, transmission costs and MISO costs. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. TheIn
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DTE Energy Company reduced the PSCR factor
Notes to 6.69 mills/kWh on July 1, 2007 based on the updated 2007 PSCR plan year projections. In Consolidated Financial Statements — (Continued)
August 2007, the MPSC approved Detroit Edison’s 2007 PSCR plan case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007. The Company filed its 2007 PSCR reconciliation case in March 2008 and updated the filing in December 2008. The updated filing requests recovery of a $41 million PSCR under-collection through its 2008 PSCR plan. Included in the 2007 PSCR reconciliation filing was the Company’s 2007 PEM reconciliation that reflects a $21 million over-collection, including interest and prior year refunds. The Company expects an order in this proceeding in the second quarter of 2009.
2008 Plan Year —In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. The Company is supporting a total 2008 power supply expense forecast of $1.3 billion that includes $1 million for the recovery of its projected 2007 PSCR under-collection. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including; fuel costs, purchased and net interchange power costs, NOx and SO2 emission allowance costs, transmission costs and MISO costs. Also included in the filing iswas a request for approval of the Company’s emission compliance strategy which includesincluded pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable wind(wind) energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On July 29, 2008, the MPSC issued a temporary order approving Detroit Edison’s request to increase the PSCR factor to 11.22 mills/kWh. In January 2009, the MPSC approved the Company’s 2008 PSCR plan and authorized the Company to charge a maximum PSCR factor of 11.22 mills/kWh for 2008.
2009 Plan Year — In September 2008, Detroit Edison filed its 2009 PSCR plan case seeking approval of a levelized PSCR factor of 17.67 mills/kWh above the amount included in base rates for residential customers and a levelized PSCR factor of 17.29 mills/kWh above the amount included in base rates for commercial and industrial customers. The Company is supporting a total power supply expense forecast of $1.73 billion. The plan also includes approximately $69 million for the recovery of its projected 2008 PSCR under-collection from all customers and approximately $12 million for the refund of its 2005 PSCR reconciliation surcharge over-collection to commercial and industrial customers only. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a renewable (wind) energy project. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including, fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowance costs, transmission costs and MISO costs. The Company self-implemented a PSCR factor of 11.64 mills/kWh above the amount included in base rates for residential customers and a PSCR factor of 11.22 mills/kWh above the amount included in base rates for commercial and industrial customers on bills rendered in January 2009. Subsequently, as a result of the December 23, 2008 MPSC order in the 2007 Detroit Edison Rate case, the Company implemented a PSCR factor of 3.18 mills/kWh below the amount included in base rates for residential customers and a PSCR factor of 3.60 mills/kWh below the amount included in base rates for commercial and industrial customers for bills rendered effective January 14, 2009.
2009 MichCon Depreciation Filing
Depreciation Filing —On June 26, 2007, the MPSC issued its final order in the generic hearings on depreciation for Michigan electric and gas utilities. The MPSC ordered Michigan utilities to file depreciation studies using the current method, a FAS 143 approach that considers the time value of money and an inflation adjusted method proposed by the Company that removes excess escalation. In compliance with the MPSC order MichCon filed its ordered depreciation studies on November 3, 2008. The various required depreciation studies indicate composite depreciation rates from 2.07% to 2.55%. The Company has proposed no change to its current composite depreciation rate of 2.97%. The Company expects an order in this proceeding in the fourth quarter of 2009.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Uncollectible ExpenseTrue-Up Mechanism (UETM) and Report of Safety and Training-Related Expenditures
2005 UETM —In March 2006, MichCon filed an application with the MPSC for approval of its UETM for 2005. This is the first filing MichCon has made under the UETM, which was approved by the MPSC in April 2005 as part of MichCon’s last general rate case. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses totaled $60 million. Thetrue-up mechanism allowsallowed MichCon to recover ninety percent90% of uncollectibles that exceeded the $37 million base. Under the formula prescribed by the MPSC, MichCon recorded an under-recovery of approximately $11 million for uncollectible expenses from May 2005 (when the mechanism took effect) through the end of 2005. In December 2006, the MPSC issued an order authorizing MichCon to implement the UETM monthly surcharge for service rendered on and after January 1, 2007.
As part of the March 2006 application with the MPSC, MichCon filed a review of its 2005 annual safety and training-related expenditures. MichCon reported that actual safety and training-related expenditures for the initial period exceeded the pro-rata amounts included in base rates and, based on the under-recovered position, recommended no refund at thisthat time. In the December 2006 order, the MPSC also approved MichCon’s 2005 safety and training report. On October 14, 2008, the State of Michigan Court of Appeals rejected the appeal of the Attorney General of the State of Michigan upholding the right of the MPSC to authorize MichCon to charge the 2005 UETM.
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2006 UETM —In March 2007, MichCon filed an application with the MPSC for approval of its UETM for 2006 requesting $33 million of under-recovery plus applicable carrying costs of $3 million. The March 2007 application included a report of MichCon’s 2006 annual safety and training-related expenditures, which showsshowed a $2 million over-recovery. In August 2007, MichCon filed revised exhibits reflecting an agreement with the MPSC Staff to net the $2 million over-recovery and associated interest related to the 2006 safety and training-related expenditures against the 2006 UETM under-recovery. An MPSC order was issued in December 2007 approving the collection of $33 million requested in the August 2007 revised filing. MichCon iswas authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2008.
2007 UETM — In March 2008, MichCon filed an application with the MPSC for approval of its UETM for 2007 requesting approximately $34 million consisting of $33 million of costs related to 2007 uncollectible expense and associated carrying charges and $1 million of under-collections for the 2005 UETM. The March 2008 application included a report of MichCon’s 2007 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. An MPSC order was issued in December 2008 approving the collection of $34 million requested in the March 2008 filing. MichCon was authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2009.
Gas Cost Recovery Proceedings
2005-2006 Plan Year —In June 2006, MichCon filed its GCR reconciliation for the2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. MPSC Staff and other intervenersintervenors filed testimony regarding the reconciliation in which they recommended disallowances related to MichCon’s implementation of its dollar cost averaging fixed price program. In January 2007, MichCon filed testimony rebutting these recommendations. OnIn December 18, 2007, the MPSC issued an order adopting the adjustments proposed by the MPSC Staff, resulting in an $8 million disallowance. Expense related to the disallowance was reflectedrecorded in the Consolidated Statements of Operations for the year ended December 31, 2007. The MPSC authorized MichCon to roll a net over-recovery, inclusive of interest, of $20 million into its2006-2007 GCR reconciliation. OnIn December 27, 2007, MichCon filed an appeal of the case with the Michigan Court of Appeals. MichCon is currently unable to predict the outcome of the appeal.
2006-2007 Plan Year —In June 2007, MichCon filed its GCR reconciliation for the2006-2007 GCR year. The filing supported a total under-recovery, including interest through March 2007, of $18 million. In
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
March 2008, the parties reached a settlement agreement that allowed for full recovery of MichCon’s GCR costs during the2006-2007 GCR year. The under-recovery, including interest through March 2007, agreed to under the settlement is $9 million and was included in the2007-2008 GCR reconciliation. An MPSC order in this case is expected in 2008.was issued on April 22, 2008 approving the settlement.
2007-2008 Plan Year / Base Gas Sale Consolidated— In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was reached by all intervening parties that providesprovided for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement providesprovided for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. The settlement agreement was approved by the MPSC onin August 21, 2007. MichCon’s gas storage enhancement projects, the main subject of the aforementioned settlement, will enable 17 billion cubic feet (Bcf) of gas to become available for cycling. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $54$41 million. This settlement providesalso provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon expects to sell in 2007 through 2009. In the fourth quarter of 2007, MichCon sold .750.75 Bcf of base gas and recognizedin 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. By enablingIn June 2008, MichCon to retainfiled its GCR reconciliation for the profit from the sale2007-2008 GCR year. The filing supported a total under-recovery, including interest through March 2008, of this gas, the settlement provides MichCon with the opportunity to earn an 11% return on equity with no customer rate increase for a period of five years from 2005 to 2010.$10 million.
2008-2009 Plan Year —In December 2007, MichCon filed its GCR plan case for the2008-2009 GCR Plan year. MichCon filed for a maximum GCR factor of $8.36 per Mcf.Mcf, adjustable by a contingent mechanism. In June 2008, MichCon made an informational filing documenting the increase in market prices for gas since its December 2007 filing and calculating its new maximum factor of $10.76 per Mcf based on its contingent mechanism. On August 26, 2008, the MPSC approved a partial settlement agreement which includes the establishment of a new maximum base GCR factor of $11.36 per Mcf that will not be subject to adjustment by contingent GCR factors for the remainder of the2008-2009 GCR plan year. An MPSC order addressing the remaining issues in this case is expected in 2009.
2009-2010 Plan Year —In December 2008, MichCon filed its GCR plan case for the2009-2010 GCR Plan year. MichCon filed for a maximum GCR factor of $8.46 per Mcf, adjustable by a contingent mechanism. An MPSC order in this case is expected in 2009.
2009 Proposed Base Gas Sale — In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the base gas to GCR customers during 2008.the2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of the 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income and not include the proceeds in the calculation of MichCon’s revenue requirements in future rate cases.
Other
In July 3, 2007, the Court of Appeals of the State of Michigan Court of Appeals published its decision with respect to an
101
appeal by Detroit Edison and others of certain provisions of a November 23, 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. Other parties have filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision. OnIn September 6, 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger control premium as well as the recovery of transmission costs
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DTE Energy and Detroit Edison areCompany
Notes to Consolidated Financial Statements — (Continued)
through the PSCR. The Company is unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.
The Company is unable to predict the outcome of the 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.
| NOTE 6 — | NUCLEAR OPERATIONS |
Fermi 2, the Company’s nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of
1,150 MW. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.
1,150 MW. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.
Property Insurance
Detroit Edison maintains several different types of 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 polices.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-week waiting period and provides an aggregate $490 million of coverage over a three-year period.
Detroit Edison has $500 million in primary coverage and $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.
In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was scheduled to expire on December 15, 2007. Effective December 26, 2007, the Terrorism Risk Insurance Program Reauthorization Act of 2007 extended the TRIA thoughthrough 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 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 $31$30 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.
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Public Liability Insurance
As required by federal law, Detroit Edison maintains $300 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. Further, under the Price-Anderson Amendments Act of 2005, deferred premium charges up to $101$117.5 million could be levied against each licensed nuclear facility, but not more than $15$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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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Decommissioning
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. Based on the actual or anticipated extended life of the nuclear plant, decommissioning expenditures for Fermi 2 are expected to be incurred primarily during the period of 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.3 billion in 20072008 dollars and $3.4 billion in 2025 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 completecompleted by 2010.2012.
The NRC has jurisdiction over the decommissioning of nuclear power plants and requires 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 decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission the nuclear facilities.Fermi 2. The Company expects the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for these unitsFermi 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 regulatory liability.
The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary.
The following table summarizes the fair value of the nuclear decommissioning trust fund assets.
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As of December 31 2008 2007 (In millions) Fermi 2 $ 649 $ 778 Fermi 1 3 13 Low level radioactive waste 33 33 Total $ 685 $ 824
| As of December 31 | ||||||||
| (in Millions) | 2007 | 2006 | ||||||
| Fermi 2 | $ | 778 | $ | 694 | ||||
| Fermi 1 | 13 | 15 | ||||||
| Low level radioactive waste | 33 | 31 | ||||||
| Total | $ | 824 | $ | 740 | ||||
At December 31, 2008, investments in the external nuclear decommissioning trust funds consisted of approximately 42% in publicly traded equity securities, 57% in fixed debt instruments and 1% in cash equivalents. The debt securities had an average maturity of approximately 5 years. At December 31, 2007, investments in the external nuclear decommissioning trust funds consisted of approximately 54% in publicly traded equity securities, 45% in fixed debt instrumentsincome and 1% in cash equivalents. The debt securities had an average maturity of approximately 5.3 years.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
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 | Year Ended December 31 | |||||||||||||||||||||||
| 2007 | 2006 | 2005 | 2008 | 2007 | 2006 | |||||||||||||||||||
| (in Millions) | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Realized gains | $ | 25 | $ | 21 | $ | 11 | $ | 34 | $ | 25 | $ | 21 | ||||||||||||
| Realized losses | $ | (17 | ) | $ | (9 | ) | $ | (8 | ) | $ | (49 | ) | $ | (17 | ) | $ | (9 | ) | ||||||
| Proceeds from sales of securities | $ | 286 | $ | 253 | $ | 201 | $ | 232 | $ | 286 | $ | 253 | ||||||||||||
Realized gains and losses and proceeds from sales of securities for the Fermi 2 and the low level Radioactive Waste funds are recorded to the asset retirement obligation regulatory asset and nuclear decommissioning regulatory liability, respectively. 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, 2008 | ||||||||
| Equity Securities | $ | 288 | $ | 65 | ||||
| Debt Securities | 388 | 17 | ||||||
| Cash and Cash Equivalents | 9 | — | ||||||
| $ | 685 | $ | 82 | |||||
| As of December 31, 2007 | ||||||||
| Equity Securities | $ | 443 | $ | 170 | ||||
| Debt Securities | 373 | 9 | ||||||
| Cash and Cash Equivalents | 8 | — | ||||||
| $ | 824 | $ | 179 | |||||
| Total | ||||||||
| Fair | Unrealized | |||||||
| (in Millions) | Value | Gains | ||||||
| As of December 31, 2007 | ||||||||
| Equity Securities | $ | 443 | $ | 170 | ||||
| Debt Securities | 373 | 9 | ||||||
| Cash and Cash Equivalents | 8 | — | ||||||
| $ | 824 | $ | 179 | |||||
| As of December 31, 2006 | ||||||||
| Equity Securities | $ | 399 | $ | 140 | ||||
| Debt Securities | 316 | 4 | ||||||
| Cash and Cash Equivalents | 25 | — | ||||||
| $ | 740 | $ | 144 | |||||
Securities held in the nuclear decommissioning trust funds are classified as available-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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Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $22$92 million and $10$22 million of unrealized losses as regulatory assets for the years ended December 31, 20072008 and 2006,2007, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, impairment charges for unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. For the yearsyear ended December 31, 2008 no impairment charges were recognized by Detroit Edison for unrealized losses incurred by the Fermi 1 trust. For the year ended December 31, 2007, and 2006, Detroit Edison recognized impairment charges of $0.2 million, in each year for unrealized losses incurred by the Fermi 1 trust.
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 a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
acceptance and disposal of spent nuclear fuel at a permanent repository. 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 used nuclear fuel storage strategy utilizing a spent fuel pool. In December 2007, Detroit Edison announced plans to move to aWe have begun work on anon-site dry cask storage methodfacility which is expected to provide sufficient storage capability for the life of the plant.plant as defined by the original operating license.
| NOTE 7 — | JOINTLY OWNED UTILITY PLANT |
Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Ownership information of the two utility plants as of December 31, 20072008 was as follows:
| Ludington | ||||||||||||||||
| Ludington | Hydroelectric | |||||||||||||||
| Hydroelectric | Belle River | Pumped Storage | ||||||||||||||
| Belle River | Pumped Storage | |||||||||||||||
| In-service date | 1984-1985 | 1973 | 1984-1985 | 1973 | ||||||||||||
| Total plant capacity | 1,026 | MW | 1,872 | MW | 1,260MW | 1,872MW | ||||||||||
| Ownership interest | * | 49 | % | * | 49 | % | ||||||||||
| Investment (in Millions) | $ | 1,575 | $ | 164 | $ | 1,588 | $ | 165 | ||||||||
| Accumulated depreciation (in Millions) | $ | 847 | $ | 101 | $ | 853 | $ | 106 | ||||||||
| * | Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to 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.
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107
Notes to Consolidated Financial Statements — INCOME TAXES(Continued)
| NOTE 8 — | 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:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Income before income taxes and minority interest | $ | 1,155 | $ | 536 | $ | 415 | $ | 819 | $ | 1,155 | $ | 536 | ||||||||||||
| Less minority interest | 4 | 1 | 37 | 5 | 4 | 1 | ||||||||||||||||||
| Income from continuing operations before tax | $ | 1,151 | $ | 535 | $ | 378 | $ | 814 | $ | 1,151 | $ | 535 | ||||||||||||
| Income tax expense at 35% statutory rate | $ | 403 | $ | 187 | $ | 132 | $ | 285 | $ | 403 | $ | 187 | ||||||||||||
| Production tax credits | (11 | ) | (12 | ) | (10 | ) | (7 | ) | (11 | ) | (12 | ) | ||||||||||||
| Investment tax credits | (8 | ) | (8 | ) | (8 | ) | (7 | ) | (8 | ) | (8 | ) | ||||||||||||
| Depreciation | (4 | ) | (4 | ) | (4 | ) | (4 | ) | (4 | ) | (4 | ) | ||||||||||||
| Employee Stock Ownership Plan dividends | (5 | ) | (5 | ) | (5 | ) | (4 | ) | (5 | ) | (5 | ) | ||||||||||||
| Medicare part D subsidy | (6 | ) | (6 | ) | (7 | ) | (5 | ) | (6 | ) | (6 | ) | ||||||||||||
| State and local income taxes, net of federal benefit | 23 | 2 | 5 | |||||||||||||||||||||
| Other, net | (5 | ) | (6 | ) | 8 | 7 | (7 | ) | (11 | ) | ||||||||||||||
| Income tax expense from continuing operations | $ | 364 | $ | 146 | $ | 106 | $ | 288 | $ | 364 | $ | 146 | ||||||||||||
| Effective federal income tax rate | 31.6 | % | 27.3 | % | 28.0 | % | ||||||||||||||||||
| Effective income tax rate | 35.4 | % | 31.6 | % | 27.3 | % | ||||||||||||||||||
The minority interest allocation reflects the adjustment to earnings to allocate partnership losses to third party owners. The tax impact of partnership earnings and losses are attributable to the partners instead of the partnerships. The minority interest allocation is therefore removed in computing income taxes associated with continuing operations.
Components of income tax expense were as follows:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| Continuing operations | ||||||||||||||||||||||||
| Current federal and other income tax expense | $ | 277 | $ | 88 | $ | 78 | ||||||||||||||||||
| Deferred federal income tax expense | 87 | 58 | 28 | |||||||||||||||||||||
| 364 | 146 | 106 | 2008 | 2007 | 2006 | |||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Continuing operations | ||||||||||||||||||||||||
| Current income taxes | ||||||||||||||||||||||||
| Federal | $ | 130 | $ | 276 | $ | 90 | ||||||||||||||||||
| State and other income tax expense | 17 | 1 | (2 | ) | ||||||||||||||||||||
| Total current income taxes | 147 | 277 | 88 | |||||||||||||||||||||
| Deferred income taxes | ||||||||||||||||||||||||
| Federal | 121 | 85 | 48 | |||||||||||||||||||||
| State and other income tax expense | 20 | 2 | 10 | |||||||||||||||||||||
| Total deferred income taxes | 141 | 87 | 58 | |||||||||||||||||||||
| Total income taxes from continuing operations | 288 | 364 | 146 | |||||||||||||||||||||
| Discontinued operations | 66 | (11 | ) | 83 | 12 | 66 | (11 | ) | ||||||||||||||||
| Cumulative effect of accounting changes | — | 1 | (2 | ) | — | — | 1 | |||||||||||||||||
| Total | $ | 430 | $ | 136 | $ | 187 | $ | 300 | $ | 430 | $ | 136 | ||||||||||||
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Production tax credits are provided for qualified fuels produced and sold by a taxpayer to an unrelated party during the taxable year. Production tax credits earned in prior years but not utilized totaled $186$224 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 havehad 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.
Investment tax credits are deferred and amortized to income over the average life of the related property.
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
106
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.
Deferred tax assets (liabilities) were comprised of the following at December 31:
| (in Millions) | 2007 | 2006 | ||||||||||||||
| 2008 | 2007 | |||||||||||||||
| (In millions) | ||||||||||||||||
| Property, plant and equipment | $ | (1,384 | ) | $ | (1,358 | ) | $ | (1,734 | ) | $ | (1,384 | ) | ||||
| Securitized regulatory assets | (621 | ) | (670 | ) | (545 | ) | (621 | ) | ||||||||
| Alternative minimum tax credit carryforward | 186 | 438 | ||||||||||||||
| Alternative minimum tax credit carry-forwards | 224 | 186 | ||||||||||||||
| Merger basis differences | 57 | 60 | 51 | 57 | ||||||||||||
| Pension and benefits | 28 | 16 | 33 | 28 | ||||||||||||
| Other comprehensive income | 62 | 113 | 81 | 62 | ||||||||||||
| Risk management assets and liabilities | 142 | 62 | ||||||||||||||
| Net operating loss carryforward | 28 | 51 | ||||||||||||||
| Derivative assets and liabilities | 109 | 142 | ||||||||||||||
| State net operating loss and credit carry-forwards | 42 | 28 | ||||||||||||||
| Other | 93 | 88 | 50 | 93 | ||||||||||||
| (1,409 | ) | (1,200 | ) | (1,689 | ) | (1,409 | ) | |||||||||
| Less valuation allowance | (28 | ) | (20 | ) | (42 | ) | (28 | ) | ||||||||
| $ | (1,437 | ) | $ | (1,220 | ) | |||||||||||
| $ | (1,731 | ) | $ | (1,437 | ) | |||||||||||
| Current deferred income tax assets | $ | 387 | $ | 245 | $ | 227 | $ | 387 | ||||||||
| Long-term deferred income tax liabilities | (1,824 | ) | (1,465 | ) | (1,958 | ) | (1,824 | ) | ||||||||
| $ | (1,437 | ) | $ | (1,220 | ) | $ | (1,731 | ) | $ | (1,437 | ) | |||||
| Deferred income tax assets | $ | 1,771 | $ | 1,834 | $ | 1,406 | $ | 1,771 | ||||||||
| Deferred income tax liabilities | (3,208 | ) | (3,054 | ) | (3,137 | ) | (3,208 | ) | ||||||||
| $ | (1,437 | ) | $ | (1,220 | ) | $ | (1,731 | ) | $ | (1,437 | ) | |||||
The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated Statements of Financial Position.
The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $28$42 million and $20$28 million at December 31, 20072008 and 2006,2007, respectively. The state net operating loss and credit carry-forwards expire in 2008from 2009 through 2026.2029. The Company has recorded valuation allowances at December 31, 20072008 and 20062007 of approximately $28$42 million and $20$28 million, respectively, a change of $8$14 million, with respect to these deferred tax assets associated with state income taxes.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
109
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
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. Based upon the level of historical taxable income and projections for future taxable income over the periods which the deferred tax assets are deductible, the Company believes it is more likely than not that it will realize the benefits of those deductible differences, net of the existing valuation allowance as of December 31, 2007.2008.
Uncertain Tax Positions
The Company adopted the provisions of FIN 48,Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (FIN 48)on January 1, 2007. This interpretation prescribes a more-likely-than-not recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, the Company recognized a $5 million increase in liabilities that was accounted for as a reduction to the January 1, 2007 balance of retained earnings.
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A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| (in Millions) | ||||||||||||
| Balance at January 1, 2007 | $ | 45 | ||||||||||
| 2008 | 2007 | |||||||||||
| (In millions) | ||||||||||||
| Balance at January 1 | $ | 22 | $ | 45 | ||||||||
| Additions for tax positions of prior years | 4 | 12 | 4 | |||||||||
| Reductions for tax positions of prior years | (8 | ) | (5 | ) | (8 | ) | ||||||
| Additions for tax positions related to the current year | 47 | — | ||||||||||
| Settlements | (15 | ) | (1 | ) | (15 | ) | ||||||
| Lapse of statute of limitations | (4 | ) | (3 | ) | (4 | ) | ||||||
| Balance at December 31, 2007 | $ | 22 | ||||||||||
| Balance at December 31 | $ | 72 | $ | 22 | ||||||||
The Company has $14$18 million of unrecognized tax benefits at December 31, 20072008, that, if recognized, would favorably impact our effective tax rate. During the next twelve12 months it is reasonably possible that the Company will settle certain federal and state tax examinations and audits. Furthermore, during the next 12 months, statutes of limitations will expire for ourthe Company’s tax returns in various states. ItTherefore, as of December 31, 2008, the Company believes that it is reasonably possible that there will be a decrease in unrecognized tax benefits of $8$5 million to $9 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 $8 million and $7 million at December 31, 2007.2008 and December 31, 2007, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $2 million during 2008 and $1 million during 2007.
The Company’s U.S. federal income tax returns for years 2004 and subsequent years remain subject to examination by the IRS. The Company’s Michigan Business Tax for the year 2008 is subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.
Michigan Business Tax
In July 12, 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan to replace the Michigan Single Business Tax (MSBT) effective January 1, 2008. The MBT is comprised of an apportioned modified gross receipts tax of 0.8 percent; and an apportioned business income tax of 4.95 percent. The MBT
110
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
provides credits for Michigan business investment, compensation, and research and development. The MBT will beis accounted for as an income tax.
In 2007, a state deferred tax liability of $224 million was recognized by the Company for cumulative differences between book and tax assets and liabilities for the consolidated group. Effective September 30, 2007, legislation was adopted by the State of Michigan creating a deduction for businesses that realize an increase in their deferred tax liability due to the enactment of the MBT. Therefore, a deferred tax asset of$224 $224 million was established related to the future deduction. The deduction will be claimed during the period of 2015 through 2029. The recognition of the enactment of the MBT did not have an impact on our income tax provision for 2007.
The 2007 state consolidated deferred tax liability was increased in 2008 by $19 million to $243 million to reflect changes in federal income tax temporary differences primarily due to an approved IRS change in accounting method for our utilities for tax year 2007. The related one-time deferred tax asset for the $224tax deduction created for businesses that realize an increase in their deferred tax liability due to enactment of the MBT was also increased by $19 million ofto $243 million. The deferred tax liabilities and assets recognized for the consolidated group, $364 million related toof our regulated entities with the remainder related to our non-regulated entities. The $364 million of deferred tax liabilities and assets recognized by our regulatedregulatory utilities were offsetincreased by $24 million to $388 million and the corresponding regulatory assets and liabilities were also increased by $24 million to $388 million in accordance with SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,as the impacts of the deferred tax liabilities and assets recognized upon enactment and amendment of the MBT will be reflected in our rates.
108
In 2008, the state consolidated deferred tax liability increased by $25 million to $268 million as of December 31, 2008 with $20 million of the increase charged to state deferred tax expense and $5 million charged to the related regulatory assets at the utilities. The regulatory asset at the utilities increased to $394 million as of December 31, 2008.
| NOTE 9 — |
Common Stock
The DTE Energy Board of Directors has authorized the repurchase of up to $1.550$1.55 billion of common stock through 2009. Through December 31, 2007,2008, repurchases of approximately $725 million of common stock were made.
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. The number of non-vested restricted stock awards is included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded.
Dividends
Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a ratio of consolidated debt to capitalization equal to or less than 0.65:1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. The effect of this provision as of December 31, 20072008 was to restrict approximately $197$555 million as payments for dividends of total retained earnings of approximately $2.8$3 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.
111
Notes to Consolidated Financial Statements — (Continued)
| NOTE 10 — | EARNINGS PER SHARE |
The Company reports both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options. Non-vested restricted stock awards are included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded. A reconciliation of both calculations is presented in the following table:
| (in Millions, except per share amounts) | 2007 | 2006 | 2005 | |||||||||
Basic Earnings per Share | ||||||||||||
| Income from continuing operations | $ | 787 | $ | 389 | $ | 272 | ||||||
| Average number of common shares outstanding | 169 | 177 | 175 | |||||||||
| Income per share of common stock based on weighted average number of shares outstanding | $ | 4.64 | $ | 2.19 | $ | 1.56 | ||||||
Diluted Earnings per Share | ||||||||||||
| Income from continuing operations | $ | 787 | $ | 389 | $ | 272 | ||||||
| Average number of common shares outstanding | 169 | 177 | 175 | |||||||||
| Incremental shares from stock-based awards | 1 | 1 | 1 | |||||||||
| Average number of dilutive shares outstanding | 170 | 178 | 176 | |||||||||
| Income per share of common stock assuming issuance of incremental shares | $ | 4.62 | $ | 2.18 | $ | 1.55 | ||||||
109
| 2008 | 2007 | 2006 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
Basic Earnings per Share | ||||||||||||
| Income from continuing operations | $ | 526 | $ | 787 | $ | 389 | ||||||
| Average number of common shares outstanding | 162 | 169 | 177 | |||||||||
| Income per share of common stock based on weighted average number of shares outstanding | $ | 3.24 | $ | 4.64 | $ | 2.19 | ||||||
Diluted Earnings per Share | ||||||||||||
| Income from continuing operations | $ | 526 | $ | 787 | $ | 389 | ||||||
| Average number of common shares outstanding | 162 | 169 | 177 | |||||||||
| Incremental shares from stock-based awards | 1 | 1 | 1 | |||||||||
| Average number of dilutive shares outstanding | 163 | 170 | 178 | |||||||||
| Income per share of common stock assuming issuance of incremental shares | $ | 3.23 | $ | 4.62 | $ | 2.18 | ||||||
Options to purchase approximately 5 million shares, 2,100 shares, of common stock in 2007,and 100,000 shares of common stock in 2008, 2007 and 2006, and two million shares in 2005respectively, 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.
112
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| NOTE 11 — | LONG-TERM DEBT |
Long-Term Debt
The Company’s long-term debt outstanding and weighted average interest rates(1)rates(1) of debt outstanding at December 31 were:
| (in Millions) | 2007 | 2006 | ||||||||||||||
| 2008 | 2007 | |||||||||||||||
| (In millions) | ||||||||||||||||
Mortgage bonds, notes, and other | ||||||||||||||||
DTE Energy Debt, Unsecured | ||||||||||||||||
| 6.7% due 2009 to 2033 | $ | 1,496 | $ | 1,669 | $ | 1,497 | $ | 1,496 | ||||||||
Detroit Edison Taxable Debt, Principally Secured | ||||||||||||||||
| 5.9% due 2010 to 2038 | 2,305 | 2,267 | 2,841 | 2,305 | ||||||||||||
Detroit Edison Tax Exempt Revenue Bonds (2) | ||||||||||||||||
| 5.3% due 2008 to 2036 | 1,213 | 1,213 | ||||||||||||||
Detroit Edison Tax-Exempt Revenue Bonds(2) | ||||||||||||||||
| 5.2% due 2011 to 2036 | 1,263 | 1,213 | ||||||||||||||
MichCon Taxable Debt, Principally Secured | ||||||||||||||||
| 6.1% due 2008 to 2033 | 715 | 745 | ||||||||||||||
| 6.1% due 2012 to 2033 | 889 | 715 | ||||||||||||||
Other Long-Term Debt, Including Non-Recourse Debt | 196 | 259 | 188 | 196 | ||||||||||||
| $ | 5,925 | $ | 6,153 | 6,678 | 5,925 | |||||||||||
| Less debt associated with assets held for sale | (22 | ) | — | — | (22 | ) | ||||||||||
| Less amount due within one year | (327 | ) | (235 | ) | (220 | ) | (327 | ) | ||||||||
| $ | 5,576 | $ | 5,918 | $ | 6,458 | $ | 5,576 | |||||||||
Securitization bonds | ||||||||||||||||
| 6.4% due 2008 to 2015 | $ | 1,185 | $ | 1,295 | ||||||||||||
| 6.4% due 2009 to 2015 | $ | 1,064 | $ | 1,185 | ||||||||||||
| Less amount due within one year | (120 | ) | (110 | ) | (132 | ) | (120 | ) | ||||||||
| $ | 1,065 | $ | 1,185 | |||||||||||||
| $ | 932 | $ | 1,065 | |||||||||||||
Trust preferred — linked securities | ||||||||||||||||
| 7.8% due 2032 | $ | 186 | $ | 186 | $ | 186 | $ | 186 | ||||||||
| 7.5% due 2044 | 103 | 103 | 103 | 103 | ||||||||||||
| $ | 289 | $ | 289 | $ | 289 | $ | 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. |
113
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Debt Issuances
In 2007,2008, the Company has issued or remarketed the following long-term debt:
| (in Millions) | Month | |||||||||||||||||||||||||
| Company | Issued | Type | Interest Rate | Maturity | Amount | Month Issued | Type | Interest Rate | Maturity | Amount | ||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||||||||
| MichCon | April | Senior Notes(1) | 5.26% | 2013 | $ | 60 | ||||||||||||||||||||
| MichCon | April | Senior Notes(1) | 6.04% | 2018 | 100 | |||||||||||||||||||||
| MichCon | April | Senior Notes(1) | 6.44% | 2023 | 25 | |||||||||||||||||||||
| Detroit Edison | December | Senior Notes (1) | 6.47 | % | March 2038 | $ | 50 | April | Tax-Exempt Revenue Bonds(2) | Variable | 2036 | 69 | ||||||||||||||
| Detroit Edison | May | Tax-Exempt Revenue Bonds(2) | Variable | 2029 | 118 | |||||||||||||||||||||
| Detroit Edison | May | Tax-Exempt Revenue Bonds(3) | 5.30% | 2030 | 51 | |||||||||||||||||||||
| MichCon | June | Senior Notes(4) | 6.78% | 2028 | 75 | |||||||||||||||||||||
| Detroit Edison | June | Senior Notes(1) | 5.60% | 2018 | 300 | |||||||||||||||||||||
| Detroit Edison | July | Tax-Exempt Revenue Bonds(5) | Variable | 2020 | 32 | |||||||||||||||||||||
| MichCon | August | Senior Notes(6) | 5.94% | 2015 | 140 | |||||||||||||||||||||
| MichCon | August | Senior Notes(6) | 6.36% | 2020 | 50 | |||||||||||||||||||||
| Detroit Edison | October | Senior Notes(1) | 6.40% | 2013 | 250 | |||||||||||||||||||||
| Detroit Edison | December | Tax-Exempt Revenue Bonds(7) | 6.75% | 2038 | 50 | |||||||||||||||||||||
| $ | 1,320 | |||||||||||||||||||||||||
| (1) | ||
| (2) | Proceeds were used to refinance auction rate Tax-Exempt Revenue Bonds. | |
| (3) | These Tax-Exempt Revenue Bonds were converted from an auction rate mode and remarketed in a fixed rate mode to maturity. | |
| (4) | Proceeds were used to repay the 6.45% Remarketable Securities due 2038 subject to mandatory or optional tender on June 30, 2008. | |
| (5) | Proceeds were used to refinance Tax-Exempt Revenue Bonds that matured July 2008. | |
| (6) | Proceeds were used to repay a portion of the $200 million MichCon 6.125% Senior Notes due September 2008. | |
| (7) | Proceeds to be used to finance the construction, acquisition, improvement and installation of certain solid waste disposal facilities at Detroit Edison’s Monroe Power Plant. |
110
Debt Retirements and Redemptions
In 2008, the following debt washas been retired, through optional redemption or payment at maturity, during 2007.maturity:
| (in Millions) | Month | |||||||||||||||||||||||||
| Company | Retired | Type | Interest Rate | Maturity | Amount | Month Retired | Type | Interest Rate | Maturity | Amount | ||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||||||||
| Detroit Edison | April | Tax-Exempt Revenue Bonds(1) | Variable | 2036 | $ | 69 | ||||||||||||||||||||
| Detroit Edison | May | Tax-Exempt Revenue Bonds(1) | Variable | 2029 | 118 | |||||||||||||||||||||
| MichCon | May | First mortgage bonds | 7.21 | % | May 2007 | $ | 30 | June | Remarketable Securities(2) | 6.45% | 2038 | 75 | ||||||||||||||
| DTE Energy | August | Senior notes | 5.63 | % | August 2007 | 173 | ||||||||||||||||||||
| Detroit Edison | December | Other long term debt | 7.61 | % | June 2011 | 47 | July | Tax-Exempt Revenue Bonds(3) | 7.00% | 2008 | 32 | |||||||||||||||
| MichCon | September | Senior Notes(4) | 6.125% | 2008 | 200 | |||||||||||||||||||||
Total Retirements | $ | 250 | ||||||||||||||||||||||||
| $ | 494 | |||||||||||||||||||||||||
114
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| (1) | These Tax-Exempt Revenue Bonds were converted from auction rate mode and subsequently redeemed with proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds. | |
| (2) | These Remarketable Securities were optionally redeemed by MichCon with proceeds from the issuance of new MichCon Senior Notes. | |
| (3) | These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds. | |
| (4) | These Senior Notes were redeemed with the proceeds from the issuance of new MichCon Senior Notes and short-term debt. |
The following table shows the scheduled debt maturities, excluding any unamortized discount or premium on debt:
| 2014 and | ||||||||||||||||||||||||||||
| 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | Total | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
| Amount to mature | $ | 352 | $ | 670 | $ | 914 | $ | 452 | $ | 560 | $ | 5,092 | $ | 8,040 | ||||||||||||||
| 2013 and | ||||||||||||||||||||||||||||
| (in Millions) | 2008 | 2009 | 2010 | 2011 | 2012 | thereafter | Total | |||||||||||||||||||||
| Amount to mature | $ | 447 | $ | 352 | $ | 670 | $ | 914 | $ | 453 | $ | 4,571 | $ | 7,407 | ||||||||||||||
Trust Preferred-Linked Securities
DTE Energy has interests in various unconsolidated trusts that were formed for 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.
The Company has the right to extend interest payment periods 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.
DTE Energy has issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with the Company’s obligations under the debt securities and related indenture, provide full and unconditional guarantees of the trusts’ obligations under the preferred securities.
Financing costs for these issuances were paid for and deferred by DTE Energy. These costs are being amortized using the straight-line method over the estimated lives of the related securities.
111
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 12 — | PREFERRED SECURITIES |
Preferred and Preference Securities — Authorized and Unissued
As of December 31, 2007,2008, the amount of authorized and unissued stock is as follows:
| Company | Type of Stock | Par Value | Shares Authorized | Type of Stock | Par Value | Shares Authorized | ||||||||||||||
| DTE Energy | Preferred | None | 5,000,000 | Preferred | None | 5,000,000 | ||||||||||||||
| Detroit Edison | Preferred | $ | 100 | 6,747,484 | Preferred | $100 | 6,747,484 | |||||||||||||
| Detroit Edison | Preference | $ | 1 | 30,000,000 | Preference | $1 | 30,000,000 | |||||||||||||
| MichCon | Preferred | $ | 1 | 7,000,000 | Preferred | $1 | 7,000,000 | |||||||||||||
| MichCon | Preference | $ | 1 | 4,000,000 | Preference | $1 | 4,000,000 | |||||||||||||
115
Notes to Consolidated Financial Statements — (Continued)
| NOTE 13 — | SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS |
DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year credit facilities are with a syndicate of banks and may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. The aggregate availability under these combined facilities is $1.9 billion as shown in the following table:
| (in Millions) | DTE Energy | Detroit Edison | MichCon | Total | ||||||||||||
| Five-year unsecured revolving facility, dated October 2005 | $ | 675 | $ | 69 | $ | 181 | $ | 925 | ||||||||
| Five-year unsecured revolving facility, dated October 2004 | 525 | 206 | 244 | 975 | ||||||||||||
| Aggregate availability | $ | 1,200 | $ | 275 | $ | 425 | $ | 1,900 | ||||||||
112
Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, at December 31, 2008, Detroit Edison and MichCon had short-term unsecured bank loans of $75 million and $50 million, respectively. Also in 2008, DTE Energy entered into two supplemental $30 million facilities to support the issuance of letters of credit. The above agreements require the Company to maintain a debt to total capitalization ratio of no more than 0.65 to l. Should the Company have delinquent debt obligations of at least $50 million to any creditor, such delinquency will be considered a default under our credit agreements.1. DTE Energy, Detroit Edison and MichCon are currently in compliance with this financial covenant. In December 2008, MichCon issued a $20 million secured short-term note, due in September 2009. The availability under these financial covenants. At December 31, 2007 and December 31, 2006, respectively,combined facilities is shown in the Company had approximately $82 million and $123 million offollowing table:
| DTE Energy | Detroit Edison | MichCon | Total | |||||||||||||
| (In millions) | ||||||||||||||||
| Five-year unsecured revolving facility, expiring October 2010 | $ | 675 | $ | 69 | $ | 181 | $ | 925 | ||||||||
| Five-year unsecured revolving facility, expiring October 2009 | 525 | 206 | 244 | 975 | ||||||||||||
| Unsecured bank loan facility, expiring July 2009 | — | 75 | — | 75 | ||||||||||||
| Unsecured bank loan facility, expiring June 2009 | — | — | 50 | 50 | ||||||||||||
| Secured floating rate note, maturing September 2009 | — | — | 20 | 20 | ||||||||||||
| One-year unsecured letter of credit facility, expiring November 2009 | 30 | — | — | 30 | ||||||||||||
| One-year unsecured letter of credit facility, expiring December 2009 | 30 | — | — | 30 | ||||||||||||
| Total credit facilities at December 31, 2008 | 1,260 | 350 | 495 | 2,105 | ||||||||||||
| Amounts outstanding at December 31, 2008: | ||||||||||||||||
| Commercial paper issuances | (77 | ) | — | (272 | ) | (349 | ) | |||||||||
| Borrowings | (100 | ) | (75 | ) | (220 | ) | (395 | ) | ||||||||
| Letters of credit | (275 | ) | — | — | (275 | ) | ||||||||||
| (452 | ) | (75 | ) | (492 | ) | (1,019 | ) | |||||||||
| Net availability at December 31, 2008 | $ | 808 | $ | 275 | $ | 3 | $ | 1,086 | ||||||||
We have other outstanding letters of credit outstanding against these facilities.which are not included in the above described facilities totaling approximately $16 million which are used for various corporate purposes.
The weighted average interest rate for short-term borrowings was 3.9% and 5.4% at December 31, 2008 and 2007, and 2006.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 $150$50 million with its clearing agent. The amount outstanding under this agreement was $13$26 million and $23$13 million at December 31, 2008 and 2007, and 2006, respectively.
116
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Detroit Edison hasterminated a $200 million short-term financing agreement secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currentlyreceivable in compliance with these covenants. The Company had an outstanding balance of $125 million and $100 million at December 31, 2007 and 2006, respectively.2008.
113
| NOTE 14 — |
Lessee— The Company leases various assets under capital and operating leases, including coal cars, 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, 20072008 were:
| Capital | Operating | Capital | Operating | |||||||||||||
| (in Millions) | Leases | Leases | ||||||||||||||
| 2008 | $ | 15 | $ | 44 | ||||||||||||
| Leases | Leases | |||||||||||||||
| (In millions) | ||||||||||||||||
| 2009 | 15 | 36 | $ | 15 | $ | 36 | ||||||||||
| 2010 | 14 | 28 | 14 | 30 | ||||||||||||
| 2011 | 12 | 22 | 12 | 27 | ||||||||||||
| 2012 | 9 | 21 | 9 | 25 | ||||||||||||
| 2013 | 9 | 21 | ||||||||||||||
| Thereafter | 41 | 82 | 32 | 99 | ||||||||||||
| Total minimum lease payments (1) | 106 | $ | 233 | |||||||||||||
| Total minimum lease payments | 91 | $ | 238 | |||||||||||||
| Less imputed interest | (24 | ) | 19 | |||||||||||||
| Present value of net minimum lease payments | 82 | 72 | ||||||||||||||
| Less Assets held for sale | (33 | ) | ||||||||||||||
| Less current portion | (8 | ) | 10 | |||||||||||||
| Non-current portion | $ | 41 | $ | 62 | ||||||||||||
Rental expense for operating leases was $49 million in 2008, $60 million in 2007, and $72 million in 2006, and $68 million in 2005.2006.
Lessor— MichCon leases a portion of its pipeline system to the Vector Pipeline Partnership through a capital lease contract that expires in 2020, with renewal options extending for five years. The components of the net investment in the capital lease at December 31, 2007,2008, were as follows:
| (in Millions) | ||||||||
| 2008 | $ | 9 | ||||||
| (In millions) | ||||||||
| 2009 | 9 | $ | 9 | |||||
| 2010 | 9 | 9 | ||||||
| 2011 | 9 | 9 | ||||||
| 2012 | 9 | 9 | ||||||
| 2013 | 9 | |||||||
| Thereafter | 71 | 62 | ||||||
| Total minimum future lease receipts | 116 | 107 | ||||||
| Residual value of leased pipeline | 40 | 40 | ||||||
| Less unearned income | (78 | ) | (70 | ) | ||||
| Net investment in capital lease | 78 | 77 | ||||||
| Less current portion | (2 | ) | 2 | |||||
| $ | 76 | $ | 75 | |||||
117
Notes to Consolidated Financial Statements — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS(Continued)
| NOTE 15 — | FAIR VALUE |
Effective January 1, 2008, the Company adopted SFAS No. 157. This Statement defines fair value, establishes a framework for measuring fair value and expands the disclosures about fair value measurements. The Company has elected the option to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009.
SFAS No. 157 defines fair value 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 is immaterial for the year ended December 31, 2008. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.
SFAS No. 157 establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. SFAS No. 157 requires that assets and liabilities 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 by SFAS No. 157 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. |
118
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2008:
| Net Balance at | ||||||||||||||||||||
| Netting | December 31, | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Adjustments(2) | 2008 | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
| Cash equivalents | $ | 36 | $ | — | $ | — | $ | — | $ | 36 | ||||||||||
| Nuclear decommissioning trusts and Other investments(1) | 492 | $ | 310 | $ | 1 | $ | — | $ | 803 | |||||||||||
| Derivative assets | 2,051 | 1,118 | 677 | (3,390 | ) | 456 | ||||||||||||||
| Total | $ | 2,579 | $ | 1,428 | $ | 678 | $ | (3,390 | ) | $ | 1,295 | |||||||||
Liabilities: | ||||||||||||||||||||
| Derivative liabilities | (2,026 | ) | (1,118 | ) | (861 | ) | 3,376 | (629 | ) | |||||||||||
| Total | $ | (2,026 | ) | $ | (1,118 | ) | $ | (861 | ) | $ | 3,376 | $ | (629 | ) | ||||||
| Net assets (liabilities) at December 31, 2008 | $ | 553 | $ | 310 | $ | (183 | ) | $ | (14 | ) | $ | 666 | ||||||||
| (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. |
The following table presents the fair value reconciliation of Level 3 derivative assets and liabilities and purchase of Other investments of $1 million measured at fair value on a recurring basis for the year ended December 31, 2008:
| (In millions) | ||||
| Liability balance as of January 1, 2008(1) | $ | (366 | ) | |
| Changes in fair value recorded in income | (10 | ) | ||
| Changes in fair value recorded in regulatory liabilities | 2 | |||
| Changes in fair value recorded in other comprehensive income | 6 | |||
| Purchases, issuances and settlements | 195 | |||
| Transfers in/out of Level 3 | (10 | ) | ||
| Liability balance as of December 31, 2008 | $ | (183 | ) | |
| 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, 2008 | $ | 129 | ||
| (1) | Balance as of January 1, 2008 includes a cumulative effect adjustment which represents an increase to beginning retained earnings related to Level 3 derivatives upon adoption of SFAS No. 157. |
Net losses of $10 million related to Level 3 derivative assets and liabilities are reported in Operating Revenues for the year ended December 31, 2008 consistent with the Company’s accounting policy. Net gains of $154 million related to Level 1 and Level 2 derivative assets and liabilities, and the impact of netting, are also reported in Operating Revenues for the year ended December 31, 2008. Transfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
which the lowest significant input became observable during the period. Transfers in/out of Level 3 are reflected as if they had occurred at the beginning of the period.
SFAS No. 157 provides for limited retrospective application, the net of which is recorded as an adjustment to beginning retained earnings in the period of adoption. As a result, the Company recorded a cumulative effect adjustment of $4 million, net of taxes, as an increase to beginning retained earnings as of January 1, 2008.
Cash Equivalents
Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized as Level 1 in the fair value hierarchy.
Nuclear Decommissioning Trusts and Other Investments
The nuclear decommissioning trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trusts and other fund 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 on actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. For non-exchange traded fixed income securities, the trustees receive prices from 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.
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 and over-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. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. 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. Derivative instruments are principally used in the Company’s Energy Trading segment.
Fair Value of Financial Instruments
The fair value of financial instruments is determined by using various market data and other valuation techniques. The table below shows the fair value relative to the carrying value for long-term debt securities. The carrying value of certain other financial instruments, such as notes payable, customer deposits and notes receivable approximate fair value and are not shown as carrying value approximates fair value. As of December 31, 2008, the Company had approximately $747 million of tax exempt securities and $120 million of taxable securities insured by insurers. Overall credit market conditions have resulted in credit rating
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
downgrades and may result in future credit rating downgrades for these insurers. The Company does not expect the impact on interest rates or fair value to be material.
| 2008 | 2007 | |||||||||||||||
| Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||
| Long-Term Debt | $ | 7.7 billion | $ | 8.0 billion | $ | 7.6 billion | $ | 7.4 billion | ||||||||
| NOTE 16 — | FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS |
The Company complies with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Under SFAS No. 133, all derivatives are recognized on the Consolidated Statement of Financial Position at their fair value unless they qualify for certain scope exceptions, including 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
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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 both the derivative and the underlying hedged exposure 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. The Company has risk management policies to monitor and decrease 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 CoalPower and Gas MidstreamIndustrial Projects segment. The fair value of all derivatives is included in “AssetsDerivative assets or liabilities from risk management and trading activities” on the Consolidated Statements of Financial Position.
Commodity Price Risk and Foreign Currency Risk
Utility Operations
Detroit Edison— 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 theseContracts that are derivatives and 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 realized. This results in the deferral of unrealized gains and losses or regulatory assets or liabilities, until realized.
MichCon— MichCon purchases, stores, transmits and distributes natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2011. MichCon may also sell forward storage and transportation capacity contracts.2012. These gas-supply firm transportation, and storage contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward storage and transportation capacity contracts. Forward firm transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.
Non-Utility Operations
Power and Industrial Projects— These business segments manage and operateon-site energy and steel related 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 derivatives and are therefore accounted for under the accrual method. The business unit also engages in coal
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emissions allowances. Certain of the physical coal contracts meet the normal purchase and sales exemption and are accounted for using the accrual method. Financial and other physical coal contracts are derivatives and are accounted for by recording changes in fair value to earnings.
Unconventional Gas Production— The Unconventional Gas Production business is engaged in unconventional gas project development and production. The Company uses derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in other comprehensive lossincome/ (loss) will be reclassified to earnings, specifically as a component of operating revenues, as the related production affects earnings through 2010. In 2008 and 2007, $0.5 million of after-tax gains and 2006, $222 million and $86 million, respectively, of after-tax losses, respectively, were reclassified to earnings,earnings. The 2007 amounts principally related to the sale of the Antrim business. See Note 3 for further discussion of the discontinuance of a portion of cash flow hedge accounting upon sale of the Antrim business. In 2008,2009, management estimates reclassifying an after-tax gain of approximately $1$3 million to earnings related to the Barnett cash flows.earnings.
Energy Trading — Commodity Price Risk —Energy Trading markets and trades wholesale electricity and natural gas physical products and energy financial instruments, and provides risk 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, specifically as a component of Operating revenues, unless certain hedge accounting criteria are met. This fair value accounting better aligns financial reporting with the way the business is managed and its performance is measured. Energy Trading experiences earnings
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Energy Trading — Foreign Currency Risk —Energy Trading has foreign currency forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company entered into these contracts to mitigate any price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. Certain of these contracts were previously designated as cash flow hedges with changes in fair value recorded to Other comprehensive income.hedges. Amounts were recorded to Other comprehensive income are classifiedand reclassified to Operating revenues or Fuel, purchased power and gas expense when the related hedged item impactsimpacted earnings.
In 2008 and 2007, and 2006, $7$1 million and $8$7 million, respectively, of after-tax losses were reclassified to earnings. InThe foreign currency hedge has been fully realized as of December 31, 2008 management estimates reclassifying an after-tax gain of approximately $1 million to earnings.and therefore, no further earnings impact is expected.
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, 20072008 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to result in material effects on the Company’s financial statements.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
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 as the related interest affects earnings through 2030.2033. In 2008,2009, the Company estimates reclassifying $4 million of losses to earnings.
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| NOTE 17 — | COMMITMENTS AND CONTINGENCIES |
| 2007 | 2006 | |||||||||||||||
| Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||
| Long-Term Debt | $7.6 billion | $7.4 billion | $8.0 billion | $7.7 billion | ||||||||||||
Electric Utility
Air— Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In MarchSince 2005, EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.1$1.4 billion through 2007.2008. The Company estimates Detroit Edison future undiscounted capital expenditures at up to $282$100 million in 20082009 and up to $2.4$2.8 billion of additional capital expenditures through 2018 to satisfy both the existing and proposed new control requirements.based on current regulations.
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 the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 20072008 in additional capital expenditures to comply with these requirements. However, a recentJanuary 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that may result 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. A decision is expected in the first quarter of 2009. Concurrently, the EPA continues to develop a revised rule, which is expected to be published in early 2009.
Contaminated Sites— Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $15 million that was accrued in 2007 and is expected to be incurred over the next several years. In addition, Detroit Edison expects to make approximately $6At December 31, 2008 and 2007, the Company had $12 million of capital improvements to the ash landfill in 2008.and $15 million, respectively, accrued for remediation.
Gas Utility
Contaminated 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. Gas Utility owns, or previously owned, 15 such 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.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
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. During 2007,2008, the Company spent approximately $2 million investigating and remediating these former MGP sites. The Company accrued an additional $1 million in remediation liabilities to increase the reserve balance to $40 million asAs of December 31, 2008 and 2007, with a corresponding increase in the regulatory asset.Company had $38 million and $40 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. However, the Company anticipates the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our 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 Company is in the process of installing new environmental equipment at our coke battery facilitiesfacility in Michigan. The Company expects the projects to be completed within two years.by the first half of 2009. The Michigan coke battery facilitiesfacility received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding 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 Company is in the process of settling historical air violations at its coke battery facility located in Pennsylvania. At this time, we cannot predict the impact of this settlement. The Company is investigating wastewater treatment technologies for the coke battery facility located in Pennsylvania. This investigation may result in capital expenditures to meet regulatory requirements. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.
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. Below are the details of specific material guarantees the Company currently provides.
Millennium Pipeline Project Guarantee
The Company owns a 26.25%26% equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium is expected to beginbegan commercial operations in NovemberDecember 2008.
On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010. The amount outstanding under this facility2010 and was $153 million atfully drawn as of December 31, 2007.2008. Proceeds of the facility are being used to fund project costs and expenses relating to the development, construction and commercial start up and testing of the pipeline project and for general corporate purposes. In addition, the facility has been utilized to reimburse the project partners for costs and expenses incurred in connection with the project for the period subsequent to June 1, 2004 through immediately prior to the closing of the facility. The Company received approximately $23.5 million in September 2007 as reimbursement for costs and expenses incurred by it during the above-mentioned period. The Company accounted for this reimbursement as a return of capital.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The Company has agreed to guarantee 26.25%26% of the borrowing facility and in the event of default by Millennium.Millennium the maximum potential amount of future payments under this guarantee is approximately $210 million. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. TheRelated to this facility, the Company has also provided performance guarantees in regardsagreed to completionguarantee 26% of Millennium to the major shippers in anMillennium’s forward-starting interest rate swaps with a notional amount of approximately $16$420 million. The Company’s exposure on the forward-starting interest rate swaps varies with changes in Treasury rates and credit swap spreads and was approximately $27 million at December 31, 2008. Because we are unable to forecast changes in Treasury rates and credit swap spreads, we are unable to estimate our maximum potential amountexposure under our share of future payments under these guarantees isMillennium’s forward-starting interest rate swaps. An incremental .25% decrease in the forward interest rate swap rates will increase our exposure by approximately $226$4 million. There are no recourse provisions or collateral that would enable us to recover any amounts paid under the guarantees, other than our share of project assets.
Parent Company Guarantee of Subsidiary Obligations
Various non-utility subsidiaries of the Company has issued guarantees forhave entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the benefitcounterparties to request that the Company post cash or letters of various non-utility subsidiary transactions. Incredit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade, certaingrade. Certain of these guarantees would requireprovisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post cash or letterscollateral upon the occurrence of a credit valued at approximately $488 million at December 31, 2007. This estimateddowngrade, 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 uponon commodity prices (primarily gas, power and gas)coal) and the provisions and maturities of the underlying agreements.transactions. As of December 31, 2008, the value of the transactions for which the Company would have been exposed to collateral requests had the Company’s credit rating been below investment grade on such date was approximately $430 million. In circumstances where an entity is downgraded below investment grade and collateral requrests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.
Other Guarantees
The Company’s other guarantees are not individually material with maximum potential payments totaling $10 million at December 31, 2007.2008.
The Company is often 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, 2008, the Company had approximately $11 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.
Labor Contracts
There are several bargaining units for the Company’s representedour union employees. InThe majority of our union employees are under contracts that expire in June and October 2007, a new three-year agreement was ratified by approximately 950 employees in our gas operations. In December 2007, a new three-year agreement was ratified by approximately 3,100 employees in our electric operations2010 and corporate services. The contracts of the remaining represented employees expire at various dates in 2008 and 2009August 2012.
Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchasepurchased steam through 2008 and2008.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The term of the Energy Purchase Agreement for the purchase of electricity runs through June 2024. In 1996, a charge to income was recorded that included a reserve forWe purchased approximately $42 million of steam purchase commitmentsand electricity in excesseach of replacement costs from 1997 through 2008. The reserve for steam purchase commitments totaling $20 million at December 31,2008, 2007 is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. The Company estimates steam and2006. We estimate electric purchase commitments from 20082009 through 2024 will not exceed $343 million. $300 million in the aggregate.
In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of the sale, Detroit Edison remains contractually obligated to buy steam of $33 million from GDRRA until 2008. Also, the Company guaranteed bank loans of $13 million that Thermal Ventures II, LP may useused for capital improvements to the steam heating system. DuringAt December 31, 2008 and 2007, the Company recordedhad reserves of $13 million related to the bank loan guarantee.
As of December 31, 2007,2008, 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 $5.9 billion from 20082009 through 2051. The Company also estimates that 20082009 capital expenditures will be approximately $1.5$1.1 billion. The Company has made certain commitments in connection with expected capital expenditures.
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Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of the Company’s 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 it records provisions for amounts considered at risk of probable loss. Management believes the Company’s previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected tomay have a material effect on the Company’s consolidated financial statements.
Other Contingencies
The Company is involved in certain 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 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 Note 5 for a discussion of contingencies related to Regulatory Matters.
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DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| NOTE 18 — | RETIREMENT BENEFITS AND TRUSTEED ASSETS |
Adoption of SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS No. 158 requires companies to (1) recognize the over funded or under funded status of defined benefit pension and other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.
The requirement to recognize the funded status of a postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. The Company adopted this requirement as of December 31, 2006. The requirement to measure plan assets and benefit obligationsIn 2008, as
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Detroit Edison and MichCon received approval from the MPSC to record the chargeimpact of the adoption of the SFAS 158 provisions related to the additional liabilityfunded status as a Regulatoryregulatory asset or liability since the traditional rate setting process allows for the recovery of pension and other postretirement plan costs.
Measurement Date
All amounts and balances reported in the following tables as of December 31, 20072008 and December 31, 20062007 are based on measurement dates of December 31, 2008 and November 30, 2007, and November 30, 2006, respectively.
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 qualified pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. In December 2007,2008, the Company contributed $150$100 million to the qualified pension plans. Also, the Company contributed $50 million to the pension plans in January 2009. The Company anticipates making up to a $150$250 million contribution to its qualified pension plans in 2008 and a $5 million contribution2009.
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DTE Energy Company
Notes to its nonqualified pension plans in 2008.Consolidated Financial Statements — (Continued)
Net pension cost includes the following components:
| Qualified Pension Plans | Nonqualified Pension Plans | Pension Plans | ||||||||||||||||||||||||||||||||||
| (in Millions) | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
| Service cost | $ | 60 | $ | 62 | $ | 64 | $ | 2 | $ | 2 | $ | 2 | $ | 55 | $ | 62 | $ | 64 | ||||||||||||||||||
| Interest cost | 174 | 172 | 169 | 4 | 4 | 3 | 190 | 178 | 176 | |||||||||||||||||||||||||||
| Expected return on plan assets | (237 | ) | (222 | ) | (218 | ) | — | — | — | (259 | ) | (237 | ) | (222 | ) | |||||||||||||||||||||
| Amortization of: | ||||||||||||||||||||||||||||||||||||
| Net actuarial loss | 57 | 57 | 67 | 2 | 2 | 1 | 32 | 59 | 59 | |||||||||||||||||||||||||||
| Prior service cost | 5 | 7 | 8 | 1 | 1 | — | 6 | 6 | 8 | |||||||||||||||||||||||||||
| Special termination benefits | 8 | 49 | — | — | — | — | — | 8 | 49 | |||||||||||||||||||||||||||
| Net pension cost | $ | 67 | $ | 125 | $ | 90 | $ | 9 | $ | 9 | $ | 6 | $ | 24 | $ | 76 | $ | 134 | ||||||||||||||||||
Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
| Pension Plans | ||||||||
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets | ||||||||
| Net actuarial loss (gain) | $ | 1,061 | $ | (255 | ) | |||
| Amortization of net actuarial gain | (32 | ) | (59 | ) | ||||
| Prior service cost | 13 | 1 | ||||||
| Amortization of prior service cost | (6 | ) | (6 | ) | ||||
| Total recognized in other comprehensive income and regulatory assets | $ | 1,036 | $ | (319 | ) | |||
| Total recognized in net periodic pension cost, Other comprehensive income and regulatory assets | $ | 1,060 | $ | (243 | ) | |||
| 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 | $ | 52 | $ | 34 | ||||
| Prior service cost | 5 | 6 | ||||||
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| Qualified Pension Plans | Nonqualified Pension Plans | |||||||||||||||
| (in Millions) | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets | ||||||||||||||||
| Net actuarial (gain) | $ | (255 | ) | $ | N/A | $ | — | $ | N/A | |||||||
| Amortization of net actuarial (gain) | (57 | ) | N/A | (2 | ) | N/A | ||||||||||
| Prior service cost | 1 | N/A | — | N/A | ||||||||||||
| Amortization of prior service (credit) | (5 | ) | N/A | (1 | ) | N/A | ||||||||||
| Total recognized in other comprehensive income and regulatory assets | $ | (316 | ) | $ | N/A | $ | (3 | ) | $ | N/A | ||||||
| Total recognized in net periodic pension cost and other comprehensive income and regulatory assets | $ | (249 | ) | $ | N/A | $ | 6 | $ | N/A | |||||||
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 | $ | 32 | $ | 56 | $ | 2 | $ | 2 | ||||||||
| Prior service cost | 5 | 5 | 1 | 1 | ||||||||||||
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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 Statement of Financial Position at December 31:
| Qualified Pension Plans | Nonqualified Pension Plans | Pension Plans | ||||||||||||||||||||||
| (in Millions) | 2007 | 2006 | 2007 | 2006 | ||||||||||||||||||||
| 2008 | 2007 | |||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
Accumulated benefit obligation, end of year | $ | 2,767 | $ | 2,934 | $ | 69 | $ | 73 | $ | 2,828 | $ | 2,836 | ||||||||||||
Change in projected benefit obligation | ||||||||||||||||||||||||
| Projected benefit obligation, beginning of year | $ | 3,171 | $ | 3,013 | $ | 75 | $ | 67 | $ | 3,050 | $ | 3,246 | ||||||||||||
| December 2007 benefit payments | (19 | ) | — | |||||||||||||||||||||
| Service cost | 60 | 62 | 2 | 2 | 55 | 62 | ||||||||||||||||||
| Interest cost | 174 | 172 | 4 | 4 | 191 | 178 | ||||||||||||||||||
| Actuarial (gain) loss | (212 | ) | 78 | — | 7 | (79 | ) | (212 | ) | |||||||||||||||
| Benefits paid | (224 | ) | (197 | ) | (9 | ) | (5 | ) | (201 | ) | (233 | ) | ||||||||||||
| Measurement date change | 22 | — | ||||||||||||||||||||||
| Special termination benefits | 8 | 49 | — | — | — | 8 | ||||||||||||||||||
| Plan amendments | 1 | (6 | ) | — | — | 13 | 1 | |||||||||||||||||
| Projected benefit obligation, end of year | $ | 2,978 | $ | 3,171 | $ | 72 | $ | 75 | $ | 3,032 | $ | 3,050 | ||||||||||||
Change in plan assets | ||||||||||||||||||||||||
| Plan assets at fair value, beginning of year | $ | 2,744 | $ | 2,617 | $ | — | $ | — | $ | 2,980 | $ | 2,744 | ||||||||||||
| December 2007 contributions | 150 | — | ||||||||||||||||||||||
| December 2007 payments | (18 | ) | — | |||||||||||||||||||||
| Actual return on plan assets | 280 | 324 | — | — | (884 | ) | 280 | |||||||||||||||||
| Company contributions | 180 | — | 9 | 5 | 106 | 189 | ||||||||||||||||||
| Measurement date change | 22 | — | ||||||||||||||||||||||
| Benefits paid | (224 | ) | (197 | ) | (9 | ) | (5 | ) | (201 | ) | (233 | ) | ||||||||||||
| Plan assets at fair value, end of year | $ | 2,980 | $ | 2,744 | $ | — | $ | — | $ | 2,155 | $ | 2,980 | ||||||||||||
| Funded status of the plans | $ | 2 | $ | (427 | ) | $ | (72 | ) | $ | (75 | ) | $ | (877 | ) | $ | (70 | ) | |||||||
| December contribution | 150 | 180 | 1 | — | — | 151 | ||||||||||||||||||
| Funded status, end of year | $ | 152 | $ | (247 | ) | $ | (71 | ) | $ | (75 | ) | $ | (877 | ) | $ | 81 | ||||||||
| Amount recorded as: | ||||||||||||||||||||||||
| Noncurrent assets | $ | 152 | $ | 71 | $ | — | $ | — | $ | — | $ | 152 | ||||||||||||
| Current liabilities | — | — | (4 | ) | (5 | ) | (6 | ) | (4 | ) | ||||||||||||||
| Noncurrent liabilities | — | (318 | ) | (67 | ) | (70 | ) | (871 | ) | (67 | ) | |||||||||||||
| $ | 152 | $ | (247 | ) | $ | (71 | ) | $ | (75 | ) | $ | (877 | ) | $ | 81 | |||||||||
Amounts recognized in accumulated other comprehensive loss, pre-tax | ||||||||||||||||||||||||
| Net actuarial loss | $ | 175 | $ | 186 | $ | 5 | $ | 7 | ||||||||||||||||
| Prior service (credit) | (8 | ) | (10 | ) | — | — | ||||||||||||||||||
Amounts recognized in regulatory assets | ||||||||||||||||||||||||
| Net actuarial loss | $ | 456 | $ | 756 | $ | 21 | $ | 21 | ||||||||||||||||
| Prior service cost | 17 | 24 | 1 | 1 | ||||||||||||||||||||
129
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| Pension Plans | ||||||||
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
Amounts recognized in Accumulated other comprehensive loss, pre-tax | ||||||||
| Net actuarial loss | $ | 204 | $ | 180 | ||||
| Prior service (credit) | (6 | ) | (8 | ) | ||||
| $ | 198 | $ | 172 | |||||
Amounts recognized in regulatory assets | ||||||||
| Net actuarial loss | $ | 1,482 | $ | 477 | ||||
| Prior service cost | 23 | 18 | ||||||
| $ | 1,505 | $ | 495 | |||||
The aggregate accumulated benefit obligation, projected benefit obligation and fair value of plan assets as of December 31, 2008 for plans with benefit obligations in excess of plan assets was $2.8 billion, $3 billion and $2.2 billion, respectively.
The aggregate accumulated benefit obligation and projected benefit obligation of plan assets as of December 31, 2007 for plans with benefit obligations in excess of plan assets was $69 million and $72 million, respectively. There was no fair value related to plans with benefit obligations in excess of plan assets as of December 31, 2007.
The aggregate accumulated benefit obligation, projected benefit obligation and fair value of plan assets as of December 31, 2007 for plans with plan assets in excess of benefit obligations was $2.8 billion, $3 billion and $3 billion, respectively.
Assumptions used in determining the projected benefit obligation and net pension costs are listed below:
| 2007 | 2006 | 2005 | ||||||||||
Projected benefit obligation | ||||||||||||
| Discount rate | 6.5 | % | 5.7 | % | 5.9 | % | ||||||
| Rate of compensation increase | 4.0 | % | 4.0 | % | 4.0 | % | ||||||
Net pension costs | ||||||||||||
| Discount rate | 5.7 | % | 5.9 | % | 6.0 | % | ||||||
| Rate of compensation increase | 4.0 | % | 4.0 | % | 4.0 | % | ||||||
| Expected long-term rate of return on plan assets | 8.75 | % | 8.75 | % | 9.0 | % | ||||||
123
| 2008 | 2007 | 2006 | ||||||||||
Projected benefit obligation | ||||||||||||
| Discount rate | 6.9% | 6.5% | 5.7% | |||||||||
| Rate of compensation increase | 4.0% | 4.0% | 4.0% | |||||||||
Net pension costs | ||||||||||||
| Discount rate | 6.5% | 5.7% | 5.9% | |||||||||
| Rate of compensation increase | 4.0% | 4.0% | 4.0% | |||||||||
| Expected long-term rate of return on plan assets | 8.75% | 8.75% | 8.75% | |||||||||
At December 31, 2007,2008, 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) | ||||||||
| 2008 | $ | 189 | ||||||
| (In millions) | ||||||||
| 2009 | 194 | $ | 199 | |||||
| 2010 | 200 | 202 | ||||||
| 2011 | 204 | 206 | ||||||
| 2012 | 212 | 213 | ||||||
| 2013 - 2017 | 1,179 | |||||||
| 2013 | 217 | |||||||
| 2014 - 2018 | 1,186 | |||||||
| Total | $ | 2,178 | $ | 2,223 | ||||
130
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The Company employs a consistent 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 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. 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. Other assets such as private equity and absolute returnhedge funds are used judiciously 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 and reduce portfolio investment risk. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.
The Company’s plans’ weighted-average asset allocations by asset category at December 31 were as follows:
| 2007 | 2006 | |||||||
| Equity securities | 66 | % | 68 | % | ||||
| Debt securities | 19 | 23 | ||||||
| Other | 15 | 9 | ||||||
| 100 | % | 100 | % | |||||
124
| 2008 | 2007 | |||||||
| U.S. Equity securities | 31 | % | 48 | % | ||||
| Non U.S. Equity securities | 16 | 18 | ||||||
| Debt securities | 24 | 19 | ||||||
| Hedge Funds and Similar Investments | 22 | 12 | ||||||
| Private Equity and Other | 7 | 3 | ||||||
| 100 | % | 100 | % | |||||
The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 20072008 were as follows:
| U.S. Equity securities | % | |||
| Non U.S. Equity securities | 20 | |||
| Debt securities | 20 | |||
| Hedge Funds and Similar Investments | 20 | |||
| Private Equity and Other | ||||
| 100 | % | |||
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 $33 million in 2008 and $29 million in each of the years 2007 2006, and 2005.2006.
131
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
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) trusts exist for represented and non-represented employees. In December 2007,2008, the Company made cash contributions of $76$116 million to its postretirement benefit plans. In January 2008,2009, the Company made cash contributions of $40 million to its postretirement benefit plans. At the discretion of management, the Company may make up to a $116an additional $130 million contribution to its VEBA trusts in 2008.2009.
Net postretirement cost includes the following components:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Service cost | $ | 62 | $ | 59 | $ | 55 | $ | 62 | $ | 62 | $ | 59 | ||||||||||||
| Interest cost | 118 | 115 | 105 | 121 | 118 | 115 | ||||||||||||||||||
| Expected return on plan assets | (67 | ) | (61 | ) | (70 | ) | (75 | ) | (67 | ) | (61 | ) | ||||||||||||
| Amortization of | ||||||||||||||||||||||||
| Net loss | 69 | 72 | 60 | 38 | 69 | 72 | ||||||||||||||||||
| Prior service (credit) | (3 | ) | (3 | ) | (2 | ) | (6 | ) | (3 | ) | (3 | ) | ||||||||||||
| Net transition obligation | 7 | 7 | 7 | 2 | 7 | 7 | ||||||||||||||||||
| Special termination benefits | 2 | 8 | — | — | 2 | 8 | ||||||||||||||||||
| Net postretirement cost | $ | 188 | $ | 197 | $ | 155 | $ | 142 | $ | 188 | $ | 197 | ||||||||||||
Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
| 2008 | 2007 | |||||||
| (In millions) | ||||||||
Other changes in plan assets and APBO recognized in other comprehensive income and regulatory assets | ||||||||
| Net actuarial loss (gain) | $ | 334 | $ | (299 | ) | |||
| Amortization of net actuarial (gain) | (39 | ) | (69 | ) | ||||
| Prior service (credit) | (1 | ) | (55 | ) | ||||
| Amortization of prior service credit | 6 | 2 | ||||||
| Amortization of transition (asset) | (2 | ) | (6 | ) | ||||
| Total recognized in other comprehensive income and regulatory assets | $ | 298 | $ | (427 | ) | |||
| Total recognized in net periodic pension cost, other comprehensive income and regulatory assets | $ | 440 | $ | (239 | ) | |||
| (In millions) | ||||||||
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 | $ | 69 | $ | 38 | ||||
| Prior service (credit) | $ | (6 | ) | $ | (6 | ) | ||
| Net transition obligation | $ | 2 | $ | 2 | ||||
125
132
| (in Millions) | 2007 | 2006 | ||||||
Other changes in plan assets and APBO recognized in other comprehensive income and regulatory assets | ||||||||
| Net actuarial (gain) | $ | (299 | ) | $ | N/A | |||
| Amortization of net actuarial (gain) | (69 | ) | N/A | |||||
| Prior service (credit) | (55 | ) | N/A | |||||
| Amortization of prior service cost | 2 | N/A | ||||||
| Amortization of transition (asset) | (6 | ) | N/A | |||||
| Total recognized in other comprehensive income and regulatory assets | $ | (427 | ) | $ | N/A | |||
| Total recognized in net periodic pension cost, other comprehensive income and regulatory assets | $ | (239 | ) | $ | N/A | |||
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 | $ | 38 | $ | 66 | ||||
| Prior service (credit) | $ | (6 | ) | $ | (2 | ) | ||
| Net transition obligation | $ | 2 | $ | 7 | ||||
126
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 Statement of Financial Position at December 31:
| (in Millions) | 2007 | 2006 | ||||||||||||||
| 2008 | 2007 | |||||||||||||||
| (In millions) | ||||||||||||||||
Change in accumulated postretirement benefit obligation | ||||||||||||||||
| Accumulated postretirement benefit obligation, beginning of year | $ | 2,184 | $ | 1,991 | $ | 1,922 | $ | 2,184 | ||||||||
| December 2007 cash flow | (6 | ) | — | |||||||||||||
| Service cost | 62 | 59 | 62 | 62 | ||||||||||||
| Interest cost | 118 | 115 | 121 | 118 | ||||||||||||
| Actuarial (gain) loss | (297 | ) | 101 | 10 | (297 | ) | ||||||||||
| Plan amendments | (55 | ) | 2 | (1 | ) | (55 | ) | |||||||||
| Medicare Part D subsidy | 7 | 1 | 7 | 7 | ||||||||||||
| Special termination benefits | 2 | 8 | — | 2 | ||||||||||||
| Measurement date change | 15 | — | ||||||||||||||
| Benefits paid | (99 | ) | (93 | ) | (98 | ) | (99 | ) | ||||||||
| Accumulated postretirement benefit obligation, end of year | $ | 1,922 | $ | 2,184 | $ | 2,032 | $ | 1,922 | ||||||||
Change in plan assets | ||||||||||||||||
| Plan assets at fair value, beginning of year | $ | 794 | $ | 713 | $ | 835 | $ | 794 | ||||||||
| December 2007 VEBA cash flow | (13 | ) | — | |||||||||||||
| Actual return on plan assets | 69 | 86 | (251 | ) | 69 | |||||||||||
| Measurement date change | 6 | — | ||||||||||||||
| Company contributions | 56 | 60 | 116 | 56 | ||||||||||||
| Benefits paid | (84 | ) | (65 | ) | (95 | ) | (84 | ) | ||||||||
| Plan assets at fair value, end of year | $ | 835 | $ | 794 | $ | 598 | $ | 835 | ||||||||
| Funded status of the plans, as of November 30 | $ | (1,087 | ) | $ | (1,390 | ) | $ | — | $ | (1,087 | ) | |||||
| December adjustment | (7 | ) | (24 | ) | — | (7 | ) | |||||||||
| Funded status, as of December 31 | $ | (1,094 | ) | $ | (1,414 | ) | $ | (1,434 | ) | $ | (1,094 | ) | ||||
| Noncurrent liabilities | $ | (1,094 | ) | $ | (1,414 | ) | $ | (1,434 | ) | $ | (1,094 | ) | ||||
Amounts recognized in accumulated other comprehensive loss, pre-tax | ||||||||||||||||
Amounts recognized in Accumulated other comprehensive loss, pre-tax | ||||||||||||||||
| Net actuarial loss | $ | 75 | $ | 85 | $ | 68 | $ | 75 | ||||||||
| Prior service (credit) | $ | (48 | ) | $ | (44 | ) | (36 | ) | (48 | ) | ||||||
| Net transition (asset) | $ | (18 | ) | $ | (35 | ) | (15 | ) | (18 | ) | ||||||
| $ | 17 | $ | 9 | |||||||||||||
Amounts recognized in regulatory assets | ||||||||||||||||
| Net actuarial loss | $ | 458 | $ | 816 | $ | 760 | $ | 458 | ||||||||
| Prior service cost | $ | 9 | $ | 36 | 3 | 9 | ||||||||||
| Net transition obligation | $ | 29 | $ | 74 | 24 | 29 | ||||||||||
| $ | 787 | $ | 496 | |||||||||||||
133
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:
| 2007 | 2006 | 2005 | ||||||||||
Projected benefit obligation | ||||||||||||
| Discount rate | 6.50 | % | 5.70 | % | 5.90 | % | ||||||
Net benefit costs | ||||||||||||
| Discount rate | 5.70 | % | 5.90 | % | 6.00 | % | ||||||
| Expected long-term rate of return on plan assets | 8.75 | % | 8.75 | % | 9.00 | % | ||||||
| Health care trend rate pre-65 | 8.00 | % | 9.00 | % | 9.00 | % | ||||||
| Health care trend rate post-65 | 7.00 | % | 8.00 | % | 8.00 | % | ||||||
| Ultimate health care trend rate | 5.00 | % | 5.00 | % | 5.00 | % | ||||||
| Year in which ultimate reached | 2011 | 2011 | 2011 | |||||||||
127
| 2008 | 2007 | 2006 | ||||||||||
Projected benefit obligation | ||||||||||||
| Discount rate | 6.90% | 6.50% | 5.70% | |||||||||
Net benefit costs | ||||||||||||
| Discount rate | 6.50% | 5.70% | 5.90% | |||||||||
| Expected long-term rate of return on plan assets | 8.75% | 8.75% | 8.75% | |||||||||
| Health care trend rate pre-65 | 7.00% | 8.00% | 9.00% | |||||||||
| Health care trend rate post-65 | 6.00% | 7.00% | 8.00% | |||||||||
| Ultimate health care trend rate | 5.00% | 5.00% | 5.00% | |||||||||
| Year in which ultimate reached | 2011 | 2011 | 2011 | |||||||||
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 $27$29 million and increased the accumulated benefit obligation by $227$241 million at December 31, 2007.2008. 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 $24$26 million and would have decreased the accumulated benefit obligation by $217$238 million at December 31, 2007.2008.
At December 31, 2007,2008, 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) | ||||||||
| 2008 | $ | 121 | ||||||
| (In millions) | ||||||||
| 2009 | 130 | $ | 127 | |||||
| 2010 | 135 | 133 | ||||||
| 2011 | 141 | 138 | ||||||
| 2012 | 145 | 140 | ||||||
| 2013 - 2017 | 780 | |||||||
| 2013 | 144 | |||||||
| 2014 - 2018 | 769 | |||||||
| Total | $ | 1,452 | $ | 1,451 | ||||
| 2007 | 2006 | |||||||
| Equity securities | 68 | % | 68 | % | ||||
| Debt securities | 20 | 25 | ||||||
| Other | 12 | 7 | ||||||
| 100 | % | 100 | % | |||||
In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. The effects of the subsidy reduced net periodic postretirement benefit costs by $14 million in 2008, $16 million in 2007, and $17 million in 2006, and $20 million in 2005.2006.
128
At December 31, 2007,2008, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:
| (in Millions) | ||||||||
| 2008 | $ | 5 | ||||||
| (In millions) | ||||||||
| 2009 | 5 | $ | 5 | |||||
| 2010 | 5 | 4 | ||||||
| 2011 | 6 | 6 | ||||||
| 2012 | 6 | 7 | ||||||
| 2013 - 2017 | 34 | |||||||
| 2013 | 7 | |||||||
| 2014 - 2018 | 35 | |||||||
| Total | $ | 61 | $ | 64 | ||||
134
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
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.
The Company’s plans’ weighted-average asset allocations by asset category at December 31 were as follows:
| 2008 | 2007 | |||||||
| U.S. Equity securities | 39 | % | 50 | % | ||||
| Non U.S. Equity securities | 17 | 18 | ||||||
| Debt securities | 26 | 20 | ||||||
| Hedge Funds and Similar Investments | 13 | 11 | ||||||
| Private Equity and Other | 5 | 1 | ||||||
| 100 | % | 100 | % | |||||
The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2008 were as follows:
| U.S. Equity securities | 27 | % | ||
| Non U.S. Equity securities | 24 | |||
| Debt securities | 16 | |||
| Hedge Funds and Similar Investments | 28 | |||
| Private Equity and Other | 5 | |||
| 100 | % | |||
Grantor Trust
MichCon maintains a Grantor Trust to fund other postretirement benefit obligations that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and MichCon can revoke the trust subject to providing the MPSC with prior notification. The Company accounts for its investment at fair value with unrealized gains and losses recorded to earnings.
| NOTE 19 — |
The DTE Energy Stock Incentive PlanCompany’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. Participants in the plan include the Company’sunits to employees and members of its Board of Directors. In 2006, the Company adopted a new Long-Term Incentive Program (LTIP).
| • | Authorized limit is 9,000,000 shares of common stock; | ||
| • | Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and | ||
| • | Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each. |
Effective January 1, 2006, the Company adopted SFAS No. 123(R),Share-Based Payment,using the modified prospective transition method. Under this method, the Company records compensation expense at fair
135
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
value over the vesting period for all awards it grants after the date it adopted the standard. In addition, the Company is required to record compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption grants of stock awards and performance shares will continue to be expensed. DTE Energy did not make the one-time election to adopt the alternative transition method described in FSP SFAS No. 123(R)-3,Transition Election Related to Accounting for the Tax Effect of Share-Based Payment Awards,but has chosen instead to follow the original guidance provided by SFAS No. 123(R) in accounting for the tax effects of stock based compensation awards.
Stock-based compensation for the reporting periods is as follows:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Stock-based compensation expense | $ | 28 | $ | 24 | $ | 13 | ||||||
| Tax benefit of compensation expense | $ | 10 | $ | 8 | $ | 5 | ||||||
129
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Stock-based compensation expense | $ | 38 | $ | 28 | $ | 24 | ||||||
| Tax benefit of compensation expense | $ | 13 | $ | 10 | $ | 8 | ||||||
The cumulative effect of the adoption of SFAS No. 123(R) in 2006 was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares. The Company has not restated any prior periods as a result of the adoption of SFAS No. 123(R). The Company generally purchases shares on the open market for options that are exercised or it may settle in cash other stock-based compensation.
Options
Options are exercisable according to the terms of the individual stock option award agreements and expire 10 years after the date of the grant. The option exercise price equals the fair value of the stock on the date that the option was granted. Stock options granted vest ratably over a three-year period.
Stock option activity was as follows:
| (in Millions) | Weighted | Aggregate | ||||||||||||||||||||||
| Weighted | Aggregate | Number of | Average | Intrinsic | ||||||||||||||||||||
| Number of | Average | Intrinsic | Options | Exercise Price | Value | |||||||||||||||||||
| Options | Exercise Price | Value | (In millions) | |||||||||||||||||||||
| Options outstanding at January 1, 2007 | 5,667,197 | $ | 41.60 | |||||||||||||||||||||
| Options outstanding at January 1, 2008 | 4,394,809 | $ | 42.37 | |||||||||||||||||||||
| Granted | 419,400 | $ | 47.57 | 811,300 | $ | 41.77 | ||||||||||||||||||
| Exercised | (1,654,148 | ) | $ | 41.07 | (104,261 | ) | $ | 32.13 | ||||||||||||||||
| Forfeited or expired | (37,640 | ) | $ | 43.45 | (88,149 | ) | $ | 44.02 | ||||||||||||||||
| Options outstanding at December 31, 2007 | 4,394,809 | $ | 42.37 | $ | 26 | |||||||||||||||||||
| Options outstanding at December 31, 2008 | 5,013,699 | $ | 42.45 | $ | — | |||||||||||||||||||
| Options exercisable at December 31, 2008 | 3,766,477 | $ | 42.17 | $ | — | |||||||||||||||||||
| Options exercisable at December 31, 2007 | 3,306,313 | $ | 41.36 | $ | 23 | |||||||||||||||||||
As of December 31, 2007,2008, the weighted average remaining contractual life for the exercisable shares is 4.914.46 years. As of December 31, 2007, 1,088,4962008, 1,247,222 options were non-vested. During 2007, 874,9842008, 610,440 options vested.
The weighted average grant date fair value of options granted during 2008, 2007, and 2006 was $4.76, $6.46, and 2005 was $6.46, $6.12, and $5.89, respectively. The intrinsic value of options exercised for the years ended December 31, 2008, 2007 and 2006 and 2005 was $1 million, $16 million, $6 million, and $8$6 million, respectively. Total option expense recognized during 2008, 2007 and 2006 was $3 million, $4 million and $6 million, respectively.
136
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:
| Weighted | ||||||||||||||||
| Weighted | Average | |||||||||||||||
| Range of | Number of | Average | Remaining | |||||||||||||
| Exercise Prices | Options | Exercise Price | Contractual Life (years) | |||||||||||||
| $ | 27.00 - $38.00 | 188,531 | $ | 30.89 | 1.88 | |||||||||||
| $ | 38.01 - $42.00 | 1,997,431 | $ | 40.64 | 4.83 | |||||||||||
| $ | 42.01 - $45.00 | 1,446,534 | $ | 43.91 | 7.00 | |||||||||||
| $ | 45.01 - $50.00 | 762,313 | $ | 46.77 | 6.72 | |||||||||||
| 4,394,809 | $ | 42.37 | 5.74 | |||||||||||||
130
| Weighted | ||||||||||||
| Weighted | Average | |||||||||||
| Range of | Number of | Average | Remaining | |||||||||
Exercise Prices | Options | Exercise Price | Contractual Life (Years) | |||||||||
| $27.00-$38.00 | 108,117 | $ | 31.75 | 1.07 | ||||||||
| $38.01-$42.00 | 2,759,759 | $ | 40.97 | 5.35 | ||||||||
| $42.01-$45.00 | 1,398,488 | $ | 43.91 | 5.98 | ||||||||
| $45.01-$50.00 | 747,335 | $ | 46.76 | 5.69 | ||||||||
| 5,013,699 | $ | 42.45 | 5.49 | |||||||||
The Company determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:
| December 31 | December 31 | December 31 | ||||||||||||||||||||||
| December 31 | December 31 | December 31 | 2008 | 2007 | 2006 | |||||||||||||||||||
| 2007 | 2006 | 2005 | ||||||||||||||||||||||
| Risk-free interest rate | 4.71 | % | 4.58 | % | 3.93 | % | 3.05% | 4.71% | 4.58% | |||||||||||||||
| Dividend yield | 4.38 | % | 4.75 | % | 4.60 | % | 5.20% | 4.38% | 4.75% | |||||||||||||||
| Expected volatility | 17.99 | % | 19.79 | % | 19.56 | % | 20.45% | 17.99% | 19.79% | |||||||||||||||
| Expected life | 6 years | 6 years | 6 years | 6 years | 6 years | 6 years | ||||||||||||||||||
In connection with the adoption of SFAS No. 123(R), the Company reviewed and updated its forfeiture, expected term and volatility assumptions. The Company modified option volatility to include both historical and implied share-price volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected life estimate is based on industry standards.
| December 31 | ||||
| (in Millions, except per share amounts) | 2005 | |||
| Net income as reported | $ | 537 | ||
| Less: total stock-based expense | (4 | ) | ||
| Pro forma net income | $ | 533 | ||
| Earnings per share | ||||
| Basic — as reported | $ | 3.07 | ||
| Basic — pro forma | $ | 3.05 | ||
| Diluted — as reported | $ | 3.05 | ||
| Diluted — pro forma | $ | 3.03 | ||
Stock Awards
Stock awards granted under the plan are restricted for varying periods, which are generally for three years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares. Prior to vesting in stock awards, the participant: (i) may not sell, transfer, pledge, exchange or otherwise dispose of shares; (ii) shall not retain custody of the share certificates; and (iii) will deliver to the Company a stock power with respect to each stock award.
The stock awards are recorded at cost that approximates fair value on the date of grant. The cost is amortized to compensation expense over the vesting period.
131
Stock award activity for the periods ended December 31 was:
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| 2007 | 2006 | 2005 | ||||||||||||||||||||||
| Fair value of awards vested (in Millions) | $ | 10 | $ | 5 | $ | 4 | $ | 18 | $ | 10 | $ | 5 | ||||||||||||
| Restricted common shares awarded | 620,125 | 282,555 | 288,360 | 389,055 | 620,125 | 282,555 | ||||||||||||||||||
| Weighted average market price of shares awarded | $ | 49.48 | $ | 43.64 | $ | 44.95 | $ | 41.96 | $ | 49.48 | $ | 43.64 | ||||||||||||
| Compensation cost charged against income (in Millions) | $ | 16 | $ | 10 | $ | 8 | $ | 20 | $ | 16 | $ | 10 | ||||||||||||
137
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The following table summarizes the Company’s stock awards activity for the period ended December 31, 2007:2008:
| Restricted | Weighted Average Grant Date | Weighted Average | ||||||||||||||
| Stock | Fair Value | Restricted | Grant Date | |||||||||||||
| Balance at January 1, 2007 | 666,136 | $ | 43.20 | |||||||||||||
| Stock | Fair Value | |||||||||||||||
| Balance at January 1, 2008 | 984,310 | $ | 47.36 | |||||||||||||
| Grants | 620,125 | $ | 49.48 | 389,055 | $ | 41.96 | ||||||||||
| Forfeitures | (62,139 | ) | $ | 46.55 | (67,165 | ) | $ | 45.45 | ||||||||
| Vested | (239,812 | ) | $ | 41.53 | (374,478 | ) | $ | 46.90 | ||||||||
| Balance at December 31, 2007 | 984,310 | $ | 47.36 | |||||||||||||
| Balance at December 31, 2008 | 931,722 | $ | 45.31 | |||||||||||||
Performance Share Awards
Performance shares awarded under the plan are for a specified number of shares of common stock that entitle the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives and market conditions. The awards vest at the end of a specified period, usually three years. The Company accounts for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the probable achievement of performance objectives; and (ii) the grant date fair valueclosing stock price market value. The settlement of the shares.award is at based on the closing price at the settlement date.
The Company recorded compensation expense as follows:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Compensation expense | $ | 7 | $ | 8 | $ | 5 | ||||||
| Cash settlements (1) | $ | 5 | $ | 4 | $ | 5 | ||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Compensation expense | $ | 15 | $ | 7 | $ | 8 | ||||||
| Cash settlements(1) | $ | 3 | $ | 5 | $ | 4 | ||||||
| (1) | Approximates the intrinsic value of the liability. |
During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance share awards are nontransferable and are subject to risk of forfeiture.
132
The following table summarizes the Company’s performance share activity for the period ended December 31, 2007:2008:
| Performance Shares | ||||
| Balance at January 1, | ||||
| Grants | ||||
| Forfeitures | ( | ) | ||
| Payouts | ( | ) | ||
| Balance at December 31, | ||||
Unrecognized Compensation Costs
As of December 31, 2007,2008, there was $37$33 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.281.33 years.
| (In Millions) | ||||||||
| Unrecognized | ||||||||
| Compensation | (in years) | |||||||
| Cost | Weighted Average to be Recognized | |||||||
| Stock awards | $ | 22 | 1.16 | |||||
| Performance shares | 13 | 1.48 | ||||||
| Options | 2 | 1.26 | ||||||
| $ | 37 | 1.28 | ||||||
138
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| Unrecognized | ||||||||
| Compensation | Weighted Average | |||||||
| Cost | to be Recognized | |||||||
| (In millions) | (In Years) | |||||||
| Stock awards | $ | 16 | 1.10 | |||||
| Performance shares | 15 | 1.53 | ||||||
| Options | 2 | 1.62 | ||||||
| $ | 33 | 1.33 | ||||||
The tax benefit realized for tax deductions related to the Company’s stock incentive plan totaled $10$13 million for the period ended December 31, 2007.2008. Approximately $1.6 million, $1.4 million, $1.6 million, and $1$1.6 million of compensation cost was capitalized as part of fixed assets during 2008, 2007, 2006, and 2005,2006, respectively.
| NOTE 20 — | SEGMENT AND RELATED INFORMATION |
Electric Utility
133
| • | The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan. |
Gas Utility
| The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers. |
Non-Utility Operations
| • | Gas Midstream | ||
| • | Unconventional Gas Production | ||
| • | Power and Industrial Projects | ||
| • | Energy Tradingprimarily |
Corporate & Other,, primarily consisting of corporate staff functions that are fully allocated to theincludes various segments based on services utilized. Additionally, Corporate & Otherholding company activities, holds certain non-utility debt and energy-related investments.
139
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated federal tax return.
Inter-segment billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal transportation services in the following segments:
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
| Electric Utility | $ | 36 | $ | 59 | $ | 207 | ||||||
| Gas Utility | 5 | 16 | 13 | |||||||||
| Coal and Gas Midstream | 191 | 180 | 152 | |||||||||
| Unconventional Gas Production | 64 | 134 | 154 | |||||||||
| Power and Industrial Projects | 23 | 6 | 6 | |||||||||
| Energy Trading | 7 | 75 | 116 | |||||||||
| Corporate & Other | (35 | ) | 7 | 54 | ||||||||
| $ | 291 | $ | 477 | $ | 702 | |||||||
134
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
| Electric Utility | $ | 16 | $ | 36 | $ | 59 | ||||||
| Gas Utility | 7 | 5 | 16 | |||||||||
| Gas Midstream | 10 | 17 | 17 | |||||||||
| Unconventional Gas Production | — | 64 | 134 | |||||||||
| Power and Industrial Projects | 80 | 197 | 169 | |||||||||
| Energy Trading | 145 | 7 | 75 | |||||||||
| Corporate & Other | (80 | ) | (35 | ) | 7 | |||||||
| $ | 178 | $ | 291 | $ | 477 | |||||||
Financial data of the business segments follows:
| Depreciation, | Depreciation, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating | Depletion & | Interest | Interest | Income | Net | Total | Capital | Operating | Depletion & | Interest | Interest | Income | Net | Total | Capital | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in Millions) | Revenue | Amortization | Income | Expense | Taxes | Income | Assets | Goodwill | Expenditures | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenue | Amortization | Income | Expense | Taxes | Income | Assets | Goodwill | Expenditures | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric Utility | $ | 4,900 | $ | 764 | $ | (7 | ) | $ | 294 | $ | 149 | $ | 317 | $ | 14,854 | $ | 1,206 | $ | 809 | $ | 4,874 | $ | 743 | $ | (6 | ) | $ | 293 | $ | 186 | $ | 331 | $ | 15,798 | $ | 1,206 | $ | 944 | ||||||||||||||||||||||||||||||||||
| Gas Utility | 1,875 | 93 | (10 | ) | 61 | 23 | 70 | 3,266 | 772 | 226 | 2,152 | 102 | (8 | ) | 66 | 41 | 85 | 3,884 | 772 | 239 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Non-utility Operations: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal and Gas Midstream | 837 | 8 | (2 | ) | 14 | 30 | 53 | 540 | 13 | 53 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Unconventional Gas Production (1) | (228 | ) | 22 | — | 13 | (117 | ) | (217 | ) | 355 | 2 | 161 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gas Midstream | 71 | 5 | (1 | ) | 7 | 24 | 38 | 316 | 9 | 19 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Unconventional Gas Production(1) | 48 | 12 | — | 2 | 47 | 84 | 314 | 2 | 101 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Power and Industrial Projects | 473 | 39 | (9 | ) | 25 | (5 | ) | 30 | 471 | 27 | 48 | 987 | 34 | (7 | ) | 20 | 11 | 40 | 1,126 | 31 | 65 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Energy Trading | 955 | 5 | (5 | ) | 11 | 17 | 32 | 1,125 | 17 | 2 | 1,388 | 5 | (5 | ) | 10 | 31 | 42 | 787 | 17 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,037 | 74 | (16 | ) | 63 | (75 | ) | (102 | ) | 2,491 | 59 | 264 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,494 | 56 | (13 | ) | 39 | 113 | 204 | 2,543 | 59 | 190 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate & Other | (15 | ) | 1 | (51 | ) | 174 | 267 | 502 | 2,369 | — | — | (13 | ) | — | (41 | ) | 154 | (52 | ) | (94 | ) | 2,365 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Reconciliation and Eliminations | (291 | ) | — | 59 | (59 | ) | — | — | — | — | — | (178 | ) | — | 49 | (49 | ) | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Total from Continuing Operations | $ | 8,506 | $ | 932 | $ | (25 | ) | $ | 533 | $ | 364 | 787 | 22,980 | 2,037 | 1,299 | $ | 9,329 | $ | 901 | $ | (19 | ) | $ | 503 | $ | 288 | 526 | 24,590 | 2,037 | 1,373 | ||||||||||||||||||||||||||||||||||||||||||
| Discontinued Operations (Note 3) | 205 | 774 | — | — | 20 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Reconciliation and Eliminations | (21 | ) | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total from Discontinued Operations | 184 | 774 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 971 | $ | 23,754 | $ | 2,037 | $ | 1,299 | $ | 546 | $ | 24,590 | $ | 2,037 | $ | 1,373 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
140
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| Depreciation, | ||||||||||||||||||||||||||||||||||||
| Operating | Depletion & | Interest | Interest | Income | Net | Total | Capital | |||||||||||||||||||||||||||||
| Revenue | Amortization | Income | Expense | Taxes | Income | Assets | Goodwill | Expenditures | ||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||
| Electric Utility | $ | 4,900 | $ | 764 | $ | (7 | ) | $ | 294 | $ | 149 | $ | 317 | $ | 14,854 | $ | 1,206 | $ | 809 | |||||||||||||||||
| Gas Utility | 1,875 | 93 | (10 | ) | 61 | 23 | 70 | 3,266 | 772 | 226 | ||||||||||||||||||||||||||
| Non-utility Operations: | ||||||||||||||||||||||||||||||||||||
| Gas Midstream | 66 | 6 | (2 | ) | 11 | 18 | 34 | 258 | 9 | 35 | ||||||||||||||||||||||||||
| Unconventional Gas Production(1) | (228 | ) | 22 | — | 13 | (117 | ) | (217 | ) | 355 | 2 | 161 | ||||||||||||||||||||||||
| Power and Industrial Projects | 1,244 | 41 | (9 | ) | 28 | 7 | 49 | 753 | 31 | 66 | ||||||||||||||||||||||||||
| Energy Trading | 924 | 5 | (5 | ) | 11 | 17 | 32 | 1,113 | 17 | 2 | ||||||||||||||||||||||||||
| 2,006 | 74 | (16 | ) | 63 | (75 | ) | (102 | ) | 2,479 | 59 | 264 | |||||||||||||||||||||||||
| Corporate & Other(1) | (15 | ) | 1 | (51 | ) | 174 | 267 | 502 | 2,369 | — | — | |||||||||||||||||||||||||
| Reconciliation and Eliminations | (291 | ) | — | 59 | (59 | ) | — | — | — | — | — | |||||||||||||||||||||||||
| Total from Continuing Operations | $ | 8,475 | $ | 932 | $ | (25 | ) | $ | 533 | $ | 364 | 787 | 22,968 | 2,037 | 1,299 | |||||||||||||||||||||
| Discontinued Operations (Note 3) | 205 | 774 | — | — | ||||||||||||||||||||||||||||||||
| Reconciliation and Eliminations | (21 | ) | — | — | — | |||||||||||||||||||||||||||||||
| Total from Discontinued Operations | 184 | 774 | — | — | ||||||||||||||||||||||||||||||||
| Total | $ | 971 | $ | 23,742 | $ | 2,037 | $ | 1,299 | ||||||||||||||||||||||||||||
| (1) | Net income of the Unconventional Gas production segment in 2008 reflects the gain recognized on the sale of Barnett shale properties. Operating |
| Depreciation, | ||||||||||||||||||||||||||||||||||||
| Operating | Depletion & | Interest | Interest | Income | Net | Total | Capital | |||||||||||||||||||||||||||||
| (in Millions) | Revenue | Amortization | Income | Expense | Taxes | Income | Assets | Goodwill | Expenditures | |||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||
| Electric Utility | $ | 4,737 | $ | 809 | $ | (4 | ) | $ | 278 | $ | 161 | $ | 325 | $ | 14,540 | $ | 1,206 | $ | 972 | |||||||||||||||||
| Gas Utility | 1,849 | 94 | (9 | ) | 67 | 11 | 50 | 3,123 | 773 | 155 | ||||||||||||||||||||||||||
| Non-utility Operations: | ||||||||||||||||||||||||||||||||||||
| Coal and Gas Midstream | 707 | 4 | (3 | ) | 10 | 28 | 50 | 435 | 13 | 53 | ||||||||||||||||||||||||||
| Unconventional Gas Production | 99 | 27 | — | 13 | 5 | 9 | 611 | 8 | 186 | |||||||||||||||||||||||||||
| Power and Industrial Projects | 409 | 48 | (8 | ) | 29 | (56 | ) | (80 | ) | 864 | 36 | 35 | ||||||||||||||||||||||||
| Energy Trading | 830 | 6 | (12 | ) | 15 | 49 | 96 | 1,220 | 17 | 2 | ||||||||||||||||||||||||||
| 2,045 | 85 | (23 | ) | 67 | 26 | 75 | 3,130 | 74 | 276 | |||||||||||||||||||||||||||
| Corporate & Other | 5 | 2 | (52 | ) | 174 | (52 | ) | (61 | ) | 2,307 | — | — | ||||||||||||||||||||||||
| Reconciliation and Eliminations | (477 | ) | — | 62 | (61 | ) | — | — | — | — | — | |||||||||||||||||||||||||
| Total from Continuing Operations | $ | 8,159 | $ | 990 | $ | (26 | ) | $ | 525 | $ | 146 | 389 | 23,100 | 2,053 | 1,403 | |||||||||||||||||||||
| Discontinued Operations (Note 3) | 43 | 685 | 4 | — | ||||||||||||||||||||||||||||||||
| Cumulative Effect of Accounting Change | 1 | — | — | — | ||||||||||||||||||||||||||||||||
| Total | $ | 433 | $ | 23,785 | $ | 2,057 | $ | 1,403 | ||||||||||||||||||||||||||||
135141
| Depreciation, | ||||||||||||||||||||||||||||||||||||
| Operating | Depletion & | Interest | Interest | Income | Net | Total | Capital | |||||||||||||||||||||||||||||
| (in Millions) | Revenue | Amortization | Income | Expense | Taxes | Income | Assets | Goodwill | Expenditures | |||||||||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||||||||||
| Electric Utility | $ | 4,462 | $ | 640 | $ | (3 | ) | $ | 267 | $ | 149 | $ | 277 | $ | 13,112 | $ | 1,207 | $ | 722 | |||||||||||||||||
| Gas Utility | 2,138 | 95 | (10 | ) | 58 | (2 | ) | 37 | 3,101 | 772 | 128 | |||||||||||||||||||||||||
| Non-utility Operations: | ||||||||||||||||||||||||||||||||||||
| Coal and Gas Midstream | 707 | 3 | (3 | ) | 4 | 22 | 45 | 373 | 12 | 28 | ||||||||||||||||||||||||||
| Unconventional Gas Production | 74 | 20 | — | 8 | 1 | 4 | 434 | 8 | 144 | |||||||||||||||||||||||||||
| Power and Industrial Projects | 428 | 48 | (5 | ) | 20 | (7 | ) | 4 | 1,043 | 37 | 29 | |||||||||||||||||||||||||
| Energy Trading | 977 | 4 | (3 | ) | 17 | (23 | ) | (43 | ) | 1,834 | 17 | 8 | ||||||||||||||||||||||||
| 2,186 | 75 | (11 | ) | 49 | (7 | ) | 10 | 3,684 | 74 | 209 | ||||||||||||||||||||||||||
| Corporate & Other | 10 | — | (40 | ) | 187 | (34 | ) | (52 | ) | 2,358 | — | 4 | ||||||||||||||||||||||||
| Reconciliation and Eliminations | (702 | ) | — | 42 | (43 | ) | — | — | — | — | — | |||||||||||||||||||||||||
| Total from Continuing Operations | $ | 8,094 | $ | 810 | $ | (22 | ) | $ | 518 | $ | 106 | 272 | 22,255 | 2,053 | 1,063 | |||||||||||||||||||||
| Discontinued Operations (Note 3) | 268 | 1,080 | 4 | 2 | ||||||||||||||||||||||||||||||||
| Cumulative Effect of Accounting Change | (3 | ) | — | — | — | |||||||||||||||||||||||||||||||
| Total | $ | 537 | $ | 23,335 | $ | 2,057 | $ | 1,065 | ||||||||||||||||||||||||||||
136
Notes to Consolidated Financial Statements — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)(Continued)
| Depreciation, | ||||||||||||||||||||||||||||||||||||
| Operating | Depletion & | Interest | Interest | Income | Net | Total | Capital | |||||||||||||||||||||||||||||
| Revenue | Amortization | Income | Expense | Taxes | Income | Assets | Goodwill | Expenditures | ||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||
| Electric Utility | $ | 4,737 | $ | 809 | $ | (4 | ) | $ | 278 | $ | 161 | $ | 325 | $ | 14,540 | $ | 1,206 | $ | 972 | |||||||||||||||||
| Gas Utility | 1,849 | 94 | (9 | ) | 67 | 11 | 50 | 3,123 | 773 | 155 | ||||||||||||||||||||||||||
| Non-utility Operations: | ||||||||||||||||||||||||||||||||||||
| Gas Midstream | 63 | 3 | (2 | ) | 8 | 15 | 28 | 290 | 9 | 37 | ||||||||||||||||||||||||||
| Unconventional Gas Production | 99 | 27 | — | 13 | 5 | 9 | 611 | 8 | 186 | |||||||||||||||||||||||||||
| Power and Industrial Projects | 1,053 | 49 | (9 | ) | 31 | (43 | ) | (58 | ) | 1,009 | 40 | 51 | ||||||||||||||||||||||||
| Energy Trading | 828 | 6 | (12 | ) | 15 | 49 | 96 | 1,114 | 17 | 2 | ||||||||||||||||||||||||||
| 2,043 | 85 | (23 | ) | 67 | 26 | 75 | 3,024 | 74 | 276 | |||||||||||||||||||||||||||
| Corporate & Other | 5 | 2 | (52 | ) | 174 | (52 | ) | (61 | ) | 2,307 | — | — | ||||||||||||||||||||||||
| Reconciliation and Eliminations | (477 | ) | — | 62 | (61 | ) | — | — | — | — | — | |||||||||||||||||||||||||
| Total from Continuing Operations | $ | 8,157 | $ | 990 | $ | (26 | ) | $ | 525 | $ | 146 | 389 | 22,994 | 2,053 | 1,403 | |||||||||||||||||||||
| Discontinued Operations (Note 3) | 43 | 685 | 4 | — | ||||||||||||||||||||||||||||||||
| Cumulative Effect of Accounting Change | 1 | — | — | — | ||||||||||||||||||||||||||||||||
| Total | $ | 433 | $ | 23,679 | $ | 2,057 | $ | 1,403 | ||||||||||||||||||||||||||||
| NOTE 21 — | SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED) |
Quarterly earnings per share may not total for the years, since quarterly computations are based on weighted average common shares outstanding during each quarter. Synthetic Fuels was reported as a discontinued operation beginning in the fourth quarter of 2007, resulting in the adjustment of prior quarterly results. See Note 3.
| First | Second | Third | Fourth | |||||||||||||||||
| (in Millions, except per share amounts) | Quarter | Quarter(1) | Quarter | Quarter(2) | Year | |||||||||||||||
2007 | ||||||||||||||||||||
| Operating Revenues | $ | 2,463 | $ | 1,692 | $ | 2,140 | $ | 2,211 | $ | 8,506 | ||||||||||
| Operating Income | $ | 270 | $ | 736 | $ | 298 | $ | 331 | $ | 1,635 | ||||||||||
| Net Income | ||||||||||||||||||||
| From continuing operations | $ | 96 | $ | 348 | $ | 152 | $ | 191 | $ | 787 | ||||||||||
| Discontinued operations | 38 | 37 | 45 | 64 | 184 | |||||||||||||||
| Total | $ | 134 | $ | 385 | $ | 197 | $ | 255 | $ | 971 | ||||||||||
| Basic Earnings per Share | ||||||||||||||||||||
| From continuing operations | $ | .54 | $ | 2.00 | $ | .93 | $ | 1.17 | $ | 4.64 | ||||||||||
| Discontinued operations | .22 | .21 | .27 | .40 | 1.09 | |||||||||||||||
| Total | $ | .76 | $ | 2.21 | $ | 1.20 | $ | 1.57 | $ | 5.73 | ||||||||||
| Diluted Earnings per Share | ||||||||||||||||||||
| From continuing operations | $ | .54 | $ | 1.99 | $ | .92 | $ | 1.17 | $ | 4.62 | ||||||||||
| Discontinued operations | .22 | .21 | .27 | .39 | 1.08 | |||||||||||||||
| Total | $ | .76 | $ | 2.20 | $ | 1.19 | $ | 1.56 | $ | 5.70 | ||||||||||
2006 | ||||||||||||||||||||
| Operating Revenues | $ | 2,361 | $ | 1,706 | $ | 2,054 | $ | 2,038 | $ | 8,159 | ||||||||||
| Operating Income | $ | 295 | $ | 138 | $ | 335 | $ | 292 | $ | 1,060 | ||||||||||
| Net Income (Loss) | ||||||||||||||||||||
| From continuing operations | $ | 115 | $ | 2 | $ | 146 | $ | 126 | $ | 389 | ||||||||||
| Discontinued operations | 20 | (35 | ) | 42 | 16 | 43 | ||||||||||||||
| Cumulative effect of accounting change | 1 | — | — | — | 1 | |||||||||||||||
| Total | $ | 136 | $ | (33 | ) | $ | 188 | $ | 142 | $ | 433 | |||||||||
| Basic Earnings (Loss) per Share | ||||||||||||||||||||
| From continuing operations | $ | .64 | $ | .01 | $ | .83 | $ | .71 | $ | 2.19 | ||||||||||
| Discontinued operations | .12 | (.20 | ) | .23 | .09 | .24 | ||||||||||||||
| Cumulative effect of accounting change | .01 | — | — | — | .01 | |||||||||||||||
| Total | $ | .77 | $ | (.19 | ) | $ | 1.06 | $ | .80 | $ | 2.44 | |||||||||
| Diluted Earnings (Loss) per Share | ||||||||||||||||||||
| From continuing operations | $ | .64 | $ | .01 | $ | .83 | $ | .71 | $ | 2.18 | ||||||||||
| Discontinued operations | .12 | (.20 | ) | .23 | .09 | .24 | ||||||||||||||
| Cumulative effect of accounting change | — | — | — | — | .01 | |||||||||||||||
| Total | $ | .76 | $ | (.19 | ) | $ | 1.06 | $ | .80 | $ | 2.43 | |||||||||
142
DTE Energy Company
Notes to Consolidated Financial Statements — (Continued)
| First | Second | Third | Fourth | |||||||||||||||||
| Quarter | Quarter(1) | Quarter | Quarter(2) | Year | ||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
2008 | ||||||||||||||||||||
| Operating Revenues | $ | 2,570 | $ | 2,251 | $ | 2,338 | $ | 2,170 | $ | 9,329 | ||||||||||
| Operating Income | $ | 429 | $ | 157 | $ | 375 | $ | 302 | $ | 1,263 | ||||||||||
| Net Income | ||||||||||||||||||||
| From continuing operations | $ | 200 | $ | 28 | $ | 169 | $ | 129 | $ | 526 | ||||||||||
| Discontinued operations | 12 | — | 8 | — | 20 | |||||||||||||||
| Total | $ | 212 | $ | 28 | $ | 177 | $ | 129 | $ | 546 | ||||||||||
| Basic Earnings per Share | ||||||||||||||||||||
| From continuing operations | $ | 1.23 | $ | .17 | $ | 1.04 | $ | .80 | $ | 3.24 | ||||||||||
| Discontinued operations | .08 | — | .05 | — | .13 | |||||||||||||||
| Total | $ | 1.31 | $ | .17 | $ | 1.09 | $ | .80 | $ | 3.37 | ||||||||||
| Diluted Earnings per Share | ||||||||||||||||||||
| From continuing operations | $ | 1.23 | $ | .17 | $ | 1.03 | $ | .80 | $ | 3.23 | ||||||||||
| Discontinued operations | .07 | — | .05 | — | .13 | |||||||||||||||
| Total | $ | 1.30 | $ | .17 | $ | 1.08 | $ | .80 | $ | 3.36 | ||||||||||
2007 | ||||||||||||||||||||
| Operating Revenues | $ | 2,462 | $ | 1,676 | $ | 2,127 | $ | 2,210 | $ | 8,475 | ||||||||||
| Operating Income | $ | 269 | $ | 721 | $ | 286 | $ | 329 | $ | 1,605 | ||||||||||
| Net Income (Loss) | ||||||||||||||||||||
| From continuing operations | $ | 96 | $ | 348 | $ | 152 | $ | 191 | $ | 787 | ||||||||||
| Discontinued operations | 38 | 37 | 45 | 64 | 184 | |||||||||||||||
| Total | $ | 134 | $ | 385 | $ | 197 | $ | 255 | $ | 971 | ||||||||||
| Basic Earnings (Loss) per Share | ||||||||||||||||||||
| From continuing operations | $ | .54 | $ | 2.00 | $ | .93 | $ | 1.17 | $ | 4.64 | ||||||||||
| Discontinued operations | .22 | .21 | .27 | .40 | 1.09 | |||||||||||||||
| Total | $ | .76 | $ | 2.21 | $ | 1.20 | $ | 1.57 | $ | 5.73 | ||||||||||
| Diluted Earnings (Loss) per Share | ||||||||||||||||||||
| From continuing operations | $ | .54 | $ | 1.99 | $ | .92 | $ | 1.17 | $ | 4.62 | ||||||||||
| Discontinued operations | .22 | .21 | .27 | .39 | 1.08 | |||||||||||||||
| Total | $ | .76 | $ | 2.20 | $ | 1.19 | $ | 1.56 | $ | 5.70 | ||||||||||
| (1) | In the second quarter of 2007, the Company recorded a $900 million ($580 million after-tax) gain on the Antrim sale transaction and $323 million ($210 million after-tax) of losses on hedge contracts associated with the Antrim sale. | |
| (2) | In the fourth quarter of 2007, the Company recorded adjustments that increased operating income by $20 million ($13 million after-tax) to correct prior amounts. These adjustments were primarily to record property, plant and equipment and deferred CTA costs at Detroit Edison for expenditures that had been expensed in earlier quarters of 2007. |
137143
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
See Item 8. Financial Statements and Supplementary Data for management’s evaluation of disclosure controls and procedures, its report on internal control over financial reporting, and its conclusion on changes in internal control over financial reporting.
| Item 9B. | Other Information |
| Item 10. | Directors, Executive Officers and Corporate Governance |
| Item 11. | Executive Compensation |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
| Item 14. | Principal Accountant Fees and Services |
138
Part IV
| Item 15. | Exhibits and Financial Statement Schedules |
| (a) | The following documents are filed as part of this Annual Report onForm 10-K. |
| (1) | Consolidated financial statements. See “Item 8 | ||
| (2) | Financial statement schedules. See “Item 8 | ||
| (3) | Exhibits. | ||
| (i) Exhibits filed herewith. | |||
| 4-252 | Ninth Supplemental Indenture, dated as of December 1, 2008 to Supplemental to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., Trustee, establishing the Floating Rate Senior Notes, 2008 Series M due 2009. | ||
| 4-253 | Forty-second Supplemental Indenture, dated as of December 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., Trustee establishing the 2008 Series M Collateral Bonds. | ||
| 10-75 | DTE Energy Company Executive Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005. | ||
| 10-76 | DTE Energy Company Supplemental Retirement Plan as Amended and Restated, effective as of January 1, 2005. | ||
| 10-77 | DTE Energy Company Supplemental Savings Plan as Amended and Restated, effective as of January 1, 2005. |
144
| 10-79 | ||
| 10-80 | DTE Energy Company Deferred Stock Compensation Plan for Non-Employee Directors as Amended and Restated, effective January 1, 2005. | |
| Computation of Ratio of Earnings to Fixed Charges. | ||
| Subsidiaries of the | ||
| Consent of Deloitte & Touche LLP. | ||
| Chief Executive Officer Section 302Form 10-K Certification of Periodic Report. | ||
| Chief Financial Officer Section 302Form 10-K Certification of Periodic Report. | ||
| 99-48 | ||
(ii) | Exhibits incorporated herein by reference. | |
| 3(a) | Amended and Restated Articles of Incorporation of DTE Energy Company, dated December 13, 1995 | |
| 3(b) | Certificate of Designation of Series A Junior Participating Preferred Stock of DTE Energy Company, dated September 23, 1997 | |
| 3(c) | Bylaws of DTE Energy Company, as amended through February 24, 2005 (Exhibit 3.1 toForm 8-K dated February 24, 2005). | |
| 4(a) | Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and Bank of New York, as trustee (Exhibit 4.1 to Registration Statement onForm S-3 (FileNo. 333-58834)). | |
| 4(b) | Supplemental Indenture, dated as of May 30, 2001, between DTE Energy Company and Bank of New York, as trustee | |
| 4(c) | Supplemental Indenture, dated as of April 5, 2002 between DTE Energy Company and Bank of New York, as trustee |
139
| 4(d) | Supplemental Indenture, dated as of April 1, 2003, between DTE Energy Company and Bank of New York, as trustee, creating 2003 Series A 6 | |
| 4(e) | Supplemental Indenture, dated as of May 15, 2006, between DTE Energy Company and Bank of New York, as trustee | |
| 4(f) | Amended and Restated Trust Agreement of DTE Energy Trust I, dated as of January 15, 2002 | |
| 4(g) | Amended and Restated Trust Agreement of DTE Energy Trust II, dated as of June 1, 2004 (Exhibit 4(q) toForm 10-Q for the quarter ended June 30, 2004). | |
| 4(h) | Trust Agreement of DTE Energy Trust III | |
| 4(i) | Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit B-1 to Detroit Edison’s Registration Statement onForm A-2 (FileNo. 2-1630)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Supplemental Indenture, dated as of December 1, 1940, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit B-14 to Detroit Edison’s Registration Statement onForm A-2 (FileNo. 2-4609)). (amendment) | ||
| Supplemental Indenture, dated as of September 1, 1947, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit B-20 to Detroit Edison’s Registration Statement onForm S-1 (FileNo. 2-7136)). (amendment) |
145
| Supplemental Indenture, dated as of March 1, 1950, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit B-22 to Detroit Edison’s Registration Statement onForm S-1 (FileNo. 2-8290)). (amendment) | ||
| Supplemental Indenture, dated as of November 15, 1951, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit B-23 to Detroit Edison’s Registration Statement onForm S-1 (FileNo. 2-9226)). (amendment) | ||
| Supplemental Indenture, dated as of August 15, 1957, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 3-B-30 to Detroit Edison’sForm 8-K dated September 11, 1957). (amendment) | ||
| Supplemental Indenture, dated as of December 1, 1966, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 2-B-32 to Detroit Edison’s Registration Statement onForm S-9 (FileNo. 2-25664)). (amendment) | ||
| Supplemental Indenture, dated as of February 15, 1990, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-212 to Detroit Edison’sForm 10-K for the year ended December 31, 2000). (1990 Series B, C, E and F) | ||
| Supplemental Indenture, dated as of May 1, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-178 to Detroit Edison’sForm 10-K for the year ended December 31, 1996). (1991 Series BP and CP) | ||
| Supplemental Indenture, dated as of May 15, 1991, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-179 to Detroit Edison’sForm 10-K for the year ended December 31, 1996). (1991 Series DP) | ||
| Supplemental Indenture, dated as of February 29, 1992, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-187 to Detroit Edison’sForm 10-Q for the quarter ended March 31, 1998). (1992 Series AP) | ||
| Supplemental Indenture, dated as of April 26, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-215 to Detroit Edison’sForm 10-K for the year ended December 31, 2000). (amendment) | ||
| Supplemental Indenture, dated as of June 30, 1993, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-216 to Detroit Edison’sForm 10-K for the year ended December 31, 2000). (1993 Series AP) | ||
| Supplemental Indenture, dated as of August 1, 1999, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-204 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 1999). (1999 Series AP, BP and CP) | ||
| Supplemental Indenture, dated as of August 1, 2000, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-210 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2000). (2000 Series BP) | ||
| Supplemental Indenture, dated as of March 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-222 to Detroit Edison’sForm 10-Q for the quarter ended March 31, 2001). (2001 Series AP) |
146
| Supplemental Indenture, dated as of May 1, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-226 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2001). (2001 Series BP) | ||
| Supplemental Indenture, dated as of August 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-227 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2001). (2001 Series CP) | ||
| Supplemental Indenture, dated as of September 15, 2001, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-228 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2001). (2001 Series D and E) | ||
| Supplemental Indenture, dated as of September 17, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’s Registration Statement onForm S-3 (FileNo. 333-100000)). (amendment and successor trustee) | ||
| Supplemental Indenture, dated as of October 15, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-230 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2002). (2002 Series A and B) | ||
| Supplemental Indenture, dated as of December 1, 2002, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-232 to Detroit Edison’sForm 10-K for the year ended December 31, 2002). (2002 Series C and D) | ||
| Supplemental Indenture, dated as of August 1, 2003, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-235 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2003). (2003 Series A) | ||
| Supplemental Indenture, dated as of March 15, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-238 to Detroit Edison’sForm 10-Q for the quarter ended March 31, 2004). (2004 Series A and B) | ||
| Supplemental Indenture, dated as of July 1, 2004, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-240 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2004). (2004 Series D) | ||
| Supplemental Indenture, dated as of April 1, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.3 to Detroit Edison’s Registration Statement onForm S-4 (FileNo. 333-123926)). (2005 Series AR and BR) | ||
| Supplemental Indenture, dated as of September 15, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.2 to Detroit Edison’sForm 8-K dated September 29, 2005). (2005 Series C) | ||
| Supplemental Indenture, dated as of September 30, 2005, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between Detroit Edison and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-248 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2005). (2005 Series E) | ||
| Supplemental Indenture, dated as of May 15, 2006, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-250 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2006). (2006 Series A) |
147
| Supplemental Indenture, dated as of December 1, 2007, to the Mortgage and Deed of Trust, dated as of October 1, 1924, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.2 to Detroit Edison’sForm 8-K dated December 18, 2007). (2007 Series A) | ||
| Supplemental Indenture, dated as of April 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between the Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-251 to the Detroit Edison’sForm 10-Q for the quarter ended March 31, 2008). (2008 Series DT) | ||
| Supplemental Indenture, dated as of May 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-253 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2008). (2008 Series ET) | ||
| Supplemental Indenture, dated as of June 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-255 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2008). (2008 Series G) | ||
| Supplemental Indenture, dated as of July 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-257 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2008). (2008 Series KT) | ||
| Supplemental Indenture, dated as of October 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A. as successor trustee(Exhibit 4-259 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2008). (2008 Series J) | ||
| Supplemental Indenture, dated as of December 1, 2008 to Mortgage and Deed of Trust dated as of October 1, 1924 between The Detroit Edison Company and The Bank of New York Mellon Trust Company N.A., as successor trustee(Exhibit 4-261 to Detroit Edison’sForm 10-K for the year ended December 31, 2008). (2008 Series LT) | ||
| 4(j) | Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-152 to Detroit Edison’s Registration Statement (FileNo. 33-50325)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Ninth Supplemental Indenture, dated as of October 10, 2001, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-229 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2001). (6.125% Senior Notes due 2010) | ||
| Tenth Supplemental Indenture, dated as of October 23, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-231 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2002). (5.20% Senior Notes due 2012 and 6.35% Senior Notes due 2032) | ||
| Eleventh Supplemental Indenture, dated as of December 1, 2002, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-233 to Detroit Edison’sForm 10-Q for the quarter ended March 31, 2003). (5.45% Senior Notes due 2032 and 5.25% Senior Notes due 2032) | ||
| Twelfth Supplemental Indenture, dated as of August 1, 2003, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-236 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2003). (51/2% Senior Notes due 2030) | ||
| Thirteenth Supplemental Indenture, dated as of April 1, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-237 to Detroit Edison’sForm 10-Q for the quarter ended March 31, 2004). (4.875% Senior Notes Due 2029 and 4.65% Senior Notes due 2028) |
148
| Fourteenth Supplemental Indenture, dated as of July 15, 2004, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-239 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2004). (2004 Series D 5.40% Senior Notes due 2014) | ||
| Sixteenth Supplemental Indenture, dated as of April 1, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’s Registration Statement onForm S-4 (FileNo. 333-123926)). (2005 Series AR 4.80% Senior Notes due 2015 and 2005 Series BR 5.45% Senior Notes due 2035) | ||
| Eighteenth Supplemental Indenture, dated as of September 15, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’sForm 8-K dated September 29, 2005). (2005 Series C 5.19% Senior Notes due October 1, 2023) | ||
| Nineteenth Supplemental Indenture, dated as of September 30, 2005, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-247 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2005). (2005 Series E 5.70% Senior Notes due 2037) | ||
| Twentieth Supplemental Indenture, dated as of May 15, 2006, to the Collateral Trust Indenture dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-249 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2006). (2006 Series A Senior Notes due 2036) | ||
| Twenty-second Supplemental Indenture, dated as of December 1, 2007, to the Collateral Trust Indenture, dated as of June 30, 1993, between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Exhibit 4.1 to Detroit Edison’sForm 8-K dated December 18, 2007). (2007 Series A Senior Notes due 2038) | ||
| Twenty-third Supplemental Indenture, dated as of April 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-252 to Detroit Edison’sForm 10-Q for the quarter ended March 31, 2008). (2008 Series DT Variable Rate Senior Notes due 2036) | ||
| Twenty-fourth Supplemental Indenture, dated as of May 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-254 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2008). (2008 Series ET Variable Rate Senior Notes due 2029) | ||
| Twenty-fifth Supplemental Indenture, dated as of June 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-256 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2008). (2008 Series G 5.60% Senior Notes due 2018) | ||
| Twenty-sixth Supplemental Indenture, dated as of July 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-258 to Detroit Edison’sForm 10-Q for the quarter ended June 30, 2008). (2008 Series KT Variable Rate Senior Notes due 2020) | ||
| Twenty-seventh Supplemental Indenture, dated as of October 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-260 to Detroit Edison’sForm 10-Q for the quarter ended September 30, 2008). (2008 Series J 6.40% Senior Notes due 2013) | ||
| Twenty-eighth Supplemental Indenture, dated as of December 1, 2008 to the Collateral Trust Indenture, dated as of June 30, 1993 between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee(Exhibit 4-262 to Detroit Edison’sForm 10-K for the year ended December 31, 2008). (2008 Series LT 6.75% Senior Notes due 2038) | ||
| 4(k) | Trust Agreement of Detroit Edison Trust I. (Exhibit 4.9 to Registration Statement onForm S-3 (FileNo. 333-100000)) | |
| 4(l) | Trust Agreement of Detroit Edison Trust II. (Exhibit 4.10 to Registration Statement onForm S-3 (FileNo. 333-100000)) |
149
| 4(m) | Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., as trustee, related to Senior Debt Securities(Exhibit 4-1 to Michigan Consolidated Gas Company Registration Statement onForm S-3 (FileNo. 333-63370)) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Fourth Supplemental Indenture dated as of February 15, 2003, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-3 to Michigan Consolidated Gas CompanyForm 10-Q for the quarter ended March 31, 2003). (5.70% Senior Notes, 2003 Series A due 2033) | ||
| Fifth Supplemental Indenture dated as of October 1, 2004, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-6 to Michigan Consolidated Gas CompanyForm 10-Q for the quarter ended September 31, 2004). (5.00% Senior Notes, 2004 Series E due 2019) | ||
| Sixth Supplemental Indenture dated as of April 1, 2008, to the Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-241 toForm 10-Q for the quarter ended March 31, 2008). (5.26% Senior Notes, 2008 Series ‘A’ due 2013, 6.04% Senior Notes, 2008 Series ‘B’ due 2018 and 6.44% Senior Notes, 2008 Series ‘C’ due 2023) | ||
| Seventh Supplemental Indenture, dated as of June 1, 2008 to Supplement to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-243 toForm 10-Q for the quarter ended June 30, 2008). (6.78% Senior Notes, 2008 Series F due 2028) | ||
| Eighth Supplemental Indenture, dated as of August 1, 2008 to Supplemental to Indenture dated as of June 1, 1998 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-251 toForm 10-Q for the quarter ended September 30, 2008). (5.94% Senior Notes, 2008 Series H due 2015 and 6.36% Senior Notes, 2008 Series I due 2020) | ||
| 4(n) | Indenture of Mortgage and Deed of Trust dated as of March 1, 1944(Exhibit 7-D to Michigan Consolidated Gas Company Registration StatementNo. 2-5252) and indentures supplemental thereto, dated as of dates indicated below, and filed as exhibits to the filings set forth below: | |
| Twenty-ninth Supplemental Indenture dated as of July 15, 1989, among Michigan Consolidated Gas Company and Citibank, N.A. and Robert T. Kirchner, as trustees, creating an issue of first mortgage bonds and providing for the modification and restatement of the Indenture of Mortgage and Deed of Trust dated as of March 1, 1944(Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement onForm S-3 (FileNo. 333-63370)) | ||
| Thirty-second Supplemental Indenture dated as of January 5, 1993 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-1 to Michigan Consolidated Gas CompanyForm 10-K for the year ended December 31, 1992). (First Mortgage Bonds Designated Secured Term Notes, Series B) | ||
| Thirty-third Supplemental Indenture dated as of May 1, 1995 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement onForm S-3 (FileNo. 33-59093)). (First Mortgage Bonds Designated Secured Medium Term Notes, Series B) | ||
| Thirty-fourth Supplemental Indenture dated as of November 1, 1996 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-2 to Michigan Consolidated Gas Company Registration Statement onForm S-3 (FileNo. 333-16285)). (First Mortgage Bonds Designated Secured Medium Term Notes, Series C) | ||
| Thirty-fifth Supplemental Indenture dated as of June 18, 1998 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee, creating an issue of first mortgage bonds designated as collateral bonds(Exhibit 4-2 to Michigan Consolidated Gas CompanyForm 8-K dated June 18, 1998) | ||
| Thirty-seventh Supplemental Indenture dated as of February 15, 2003 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-4 to Michigan Consolidated Gas CompanyForm 10-Q for the quarter ended March 31, 2003). (5.70% collateral bonds due 2033) |
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| Thirty-eighth Supplemental Indenture dated as of October 1, 2004 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-5 to Michigan Consolidated Gas CompanyForm 10-Q for the quarter ended September 31, 2004). (2004 Series E collateral bonds) | ||
| Thirty-ninth Supplemental Indenture, dated as of April 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-240 toForm 10-Q for the quarter ended March 31, 2008). (2008 Series A, B and C Collateral Bonds) | ||
| Fortieth Supplemental Indenture, dated as of June 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-242 toForm 10-Q for the quarter ended June 30, 2008). (2008 Series F Collateral Bonds) | ||
| Forty-first Supplemental Indenture, dated as of August 1, 2008 to Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 between Michigan Consolidated Gas Company and Citibank, N.A., trustee(Exhibit 4-250 toForm 10-Q for the quarter ended September 30, 2008). (2008 Series H and I Collateral Bonds) | ||
| 10(a) | Form of | |
| Certain arrangements pertaining to the employment of Anthony F. Earley, Jr. with The Detroit Edison Company, dated April 25, 1994 | ||
| Certain arrangements pertaining to the employment of Gerard M. Anderson with The Detroit Edison Company, dated October 6, 1993 | ||
| Certain arrangements pertaining to the employment of David E. Meador with The Detroit Edison Company, dated January 14, 1997 | ||
| Certain arrangements pertaining to the employment of Bruce D. Peterson, dated May 22, 2002 | ||
| Termination and Consulting Agreement, dated as of October 4, 1999, among DTE Energy Company, MCN Energy Group Inc., DTE Enterprises Inc. and A.R. Glancy, III | ||
| Amended and Restated Post-Employment Income Agreement, dated March 23, 1998, between The Detroit Edison Company and Anthony F. Earley, Jr. | ||
| DTE Energy Company Annual Incentive Plan | ||
| DTE Energy Company 2001 Stock Incentive Plan | ||
| DTE Energy Company 2006 Long-Term Incentive Plan (Annex A to DTE Energy’s Definitive Proxy Statement dated March 24, 2006). | ||
| 10(k) | ||
| First Amendment, dated February 8, 2007 to the DTE Energy Company |
140
| 10(l) | ||
| DTE Energy Company Retirement Plan for Non-Employee Directors’ Fees (as amended and restated effective as of December 31, 1998) | ||
141
| The Detroit Edison Company Supplemental Long-Term Disability Plan, dated January 27, 1997 | ||
| Description of Executive Life Insurance Plan | ||
| Executive Vehicle Plan of The Detroit Edison Company, dated as of September 1, 1999 |
151
| DTE Energy Affiliates Nonqualified Plans Master Trust, effective as of May 1, 2003 | ||
| Form of DTE Energy Five-Year Credit Agreement, dated as of October 17, 2005, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N. A., as Co-Syndication Agents (Exhibit 10.1 toForm 8-K dated October 17, 2005). | ||
| 10(s) | Form of Amendment No. 1 to The Detroit Edison Company’s Five-Year Credit Agreement, dated as of January 10, 2007, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 toForm 8-K dated January 10, 2007). | |
| Amendment No. 1 to Five-Year Credit Agreement, dated as of January 10, 2007, by and among, DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 toForm 8-K dated January 10, 2007). | ||
| Form of Second Amended and Restated Five-Year Credit Agreement, dated as of October 17, 2005, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 toForm 8-K dated October 17, 2005). | ||
| Amendment No. 1 to Second Amended and Restated Five-Year Credit Agreement, dated as of January 10, 2007 by and among DTE Energy Company, the lenders party thereto, and Citibank, N.A., as Administrative Agent and Barclays Bank PLC and JP Morgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 toForm 8-K dated January 10, 2007). | ||
| Form of Director Restricted Stock Agreement (Exhibit 10.1 toForm 8-K dated June 23, 2005). | ||
| Form of Director Restricted Stock Agreement pursuant to the DTE Energy Company Long-Term Incentive Plan (Exhibit 10.1 toForm 8-K dated June 29, 2006). | ||
| Form ofChange-in-Control Severance Agreement, dated as of November 8, 2007, between DTE Energy Company and each of Anthony F Earley, Jr., Gerard M. Anderson, Robert J. Buckler, | ||
| 10(z) | Form of The Detroit Edison Company’s Five-Year Credit Agreement, dated as of October 17, 2005, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 toForm 8-K dated October 17, 2005). | |
| 10(aa) | Form of Second Amended and Restated Five-Year Credit Agreement, dated as of October 17, 2005, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 toForm 8-K dated October 17, 2005). | |
| 10(bb) | Form of Amendment No. 1 to Second Amended and Restated Five-Year Credit Agreement dated as of January 10, 2007, by and among The Detroit Edison Company, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.2 toForm 8-K dated January 10, 2007). | |
| 10(cc) | Form of Second Amended and Restated Five-Year Credit Agreement dated as of October 17, 2005, by and among Michigan Consolidated Gas Company, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank PLC and Citibank, N.A. as Co-Syndication Agents (Exhibit 10.2 toForm 8-K dated October 17, 2005). | |
| 10(dd) | Form of Amendment No. 1 to Five-Year Credit Agreement dated as of January 10, 2007, by and among Michigan Consolidated Gas Company, the lenders party thereto, JPMorgan Chase Bank, N. A., as Administrative Agent, and Barclays Bank PLC and Citibank, N.A., as Co-Syndication Agents (Exhibit 10.1 toForm 8-K dated January 10, 2007). | |
| 10(ff) | Form of Five-Year Credit Agreement dated as of October 17, 2005, by and among Michigan Consolidated Gas Company, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank PLC and Citibank, N.A., as Co-Syndication Agents (Exhibit 10.1 toForm 8-K dated October 17, 2005). |
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| 10(ee) | Form of Amendment No. 1 to Second Amended and Restated Five-Year Credit Arrangement dated as of January 10, 2007, by and among Michigan Consolidated Gas Company, the lenders party thereto JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Bank PLC and Citibank, N.A., as Co-Syndication Agents (Exhibit 10.2 toForm 8-K dated January 10, 2007). | |
| 99(a) | Master Trust Agreement (“Master Trust”), dated as of June 30, 1994, between DTE Energy Company, as successor, and Fidelity Management Trust Company relating to the Savings and Investment Plans | |
| 99(b) | First Amendment, dated as of February 1, 1995, to Master Trust | |
| 99(c) | Second Amendment, dated as of February 1, 1995, to Master Trust | |
| 99(d) | Third Amendment, effective January 1, 1996, to Master Trust | |
| 99(e) | Fourth Amendment, dated as of August 1, 1996, to Master Trust | |
| 99(f) | Fifth Amendment, dated as of January 1, 1998, to Master Trust |
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| 99(g) | Sixth Amendment, dated as of September 1, 1998, to Master Trust | |
| 99(h) | Seventh Amendment, dated as of December 15, 1999, to Master Trust | |
| 99(i) | Eighth Amendment, dated as of February 1, 2000, to Master Trust | |
| 99(j) | Ninth Amendment, dated as of April 1, 2000, to Master Trust | |
| 99(k) | Tenth Amendment, dated as of May 1, 2000, to Master Trust | |
| 99(l) | Eleventh Amendment, dated as of July 1, 2000, to Master Trust | |
| 99(m) | Twelfth Amendment, dated as of August 1, 2000, to Master Trust | |
| 99(n) | Thirteenth Amendment, dated as of December 21, 2001, to Master Trust | |
| 99(o) | Fourteenth Amendment, dated as of March 1, 2002, to Master Trust | |
| 99(p) | Fifteenth Amendment, dated as of January 1, 2002, to Master Trust | |
| 99(q) | Sixteenth Amendment, to Master Trust, dated as of July 30, 2004, to Master Trust(Exhibit 99-25 toForm 10-K for the year ended December 31, 2007). | |
| 99(s) | Nineteenth Amendment, dated as of July 31, 2007, to Master Trust(Exhibit 99-27 toForm 10-K for the year ended December 31, 2007). | |
| (iii) Exhibits furnished herewith: | ||
| Chief Executive Officer Section 906Form 10-K Certification of Periodic Report. | ||
| Chief Financial Officer Section 906Form 10-K Certification of Periodic Report. |
143153
DTE Energy Company
Schedule II
| Year Ending December 31, | ||||||||||||
| (in Millions) | 2007 | 2006 | 2005 | |||||||||
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statement of Financial Position) | ||||||||||||
| Balance at Beginning of Period | $ | 170 | $ | 136 | $ | 129 | ||||||
| Additions: | ||||||||||||
| Charged to costs and expenses | 133 | 120 | 106 | |||||||||
| Charged to other accounts (1) | 12 | 7 | 9 | |||||||||
| Deductions (2) | (133 | ) | (93 | ) | (108 | ) | ||||||
| Balance At End of Period | $ | 182 | $ | 170 | $ | 136 | ||||||
| Year Ending December 31, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| (In millions) | ||||||||||||
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statement of Financial Position) | ||||||||||||
| Balance at Beginning of Period | $ | 182 | $ | 170 | $ | 136 | ||||||
| Additions: | ||||||||||||
| Charged to costs and expenses | 198 | 133 | 120 | |||||||||
| Charged to other accounts(1) | 18 | 12 | 7 | |||||||||
| Deductions(2) | (133 | ) | (133 | ) | (93 | ) | ||||||
| Balance at End of Period | $ | 265 | $ | 182 | $ | 170 | ||||||
| (1) | Collection of accounts previously written | |
| (2) | Uncollectible accounts written off. |
| Year Ending December 31, | Year Ending December 31, | |||||||||||||||||||||||
| (in Millions) | 2007 | 2006 | 2005 | |||||||||||||||||||||
| 2008 | 2007 | 2006 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
Note Receivable Reserve | ||||||||||||||||||||||||
| Balance at Beginning of Period | $ | 65 | $ | — | $ | — | $ | 4 | $ | 65 | $ | — | ||||||||||||
| Additions: | ||||||||||||||||||||||||
| Charged to costs and expenses — shown as deduction in the Consolidated Statement of Financial Position from: | ||||||||||||||||||||||||
| Other Current Assets | — | 50 | — | — | — | 50 | ||||||||||||||||||
| Notes Receivable | — | 15 | — | — | — | 15 | ||||||||||||||||||
| Deductions | (61 | ) | — | — | (4 | ) | (61 | ) | — | |||||||||||||||
| Balance At End of Period | $ | 4 | $ | 65 | $ | — | ||||||||||||||||||
| Balance at End of Period | $ | — | $ | 4 | $ | 65 | ||||||||||||||||||
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 27, 2009
DTE ENERGY COMPANY
(Registrant)
(Registrant)
| By | /s/ ANTHONY F. EARLEY, JR. |
Anthony F. Earley, Jr.
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
| By | /s/ ANTHONY F. EARLEY, JR. Chairman of the Board and Chief Executive Officer | ||
| By | /s/ PETER B. OLEKSIAK Vice President and Controller, and Chief Accounting Officer | ||
| By | /s/ LILLIAN BAUDER | ||
| By | /s/ W. FRANK FOUNTAIN, JR. | ||
| By | /s/ ALLAN D. GILMOUR | ||
| By | /s/ ALFRED R. GLANCY III | ||
| By | /s/ FRANK M. HENNESSEY |
| By | /s/ | |||||
| By | /s/ | |||||
| By | /s/ | |||||
| By | /s/ ALLAN D. GILMOUR | |||||
| By | /s/ | |||||
| By | /s/ ALFRED R. GLANCY III | |||||
| By | /s/ | |||||
| By | /s/ | |||||
| By | /s/ JAMES H. VANDENBERGHE | |||||
Date: February 27, 2009
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