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
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 regulation. Electric and gas rates for our utilities are set by the MPSC and the FERC and cannot be increased without regulatory authorization. We may be negatively impacted by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Our ability to recover costs may be impacted by the time lag between the incurrence of costs and the recovery of the costs in customers’ rates. 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 performance. The electric Customer Choice program, as originally contemplated in Michigan, anticipated an eventual transition to a totally deregulated and competitive environment where customers would be charged market-based rates for their electricity. The State of Michigan currently experiences a hybrid market, where the MPSC continues to regulate electric rates for our customers, while alternative electric suppliers charge market-based rates. In addition, such regulated electric rates for certain groups of our customers exceed the cost of service to those
customers. Due to distorted pricing mechanisms during the initial implementation period of electric Customer Choice, many commercial customers chose alternative electric suppliers. MPSC rate orders and recent energy legislation enacted by the State of Michigan are phasing out the pricing disparity over five years and have placed a cap on the total potential Customer Choice related migration. Recent higher wholesale electric prices have also resulted in some former electric Customer Choice customers migrating back to Detroit Edison for electric generation service. However, even with the electric Customer Choice-related relief received in recent Detroit Edison rate orders and the legislated 10 percent cap on participation in the electric Customer Choice program, there continues to be financial risk associated with the electric Customer Choice program. Electric Customer Choice migration is sensitive to market price and bundled electric service price increases.
Weather significantly affects operations. Deviations from normal hot and cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow. Ice storms, tornadoes, or high winds can damage the electric distribution system infrastructure and require us to perform emergency repairs and incur material unplanned expenses. The expenses of storm restoration efforts may not be fully recoverable through the regulatory process.
Operation of a nuclear facility subjects us to risk. Ownership of an operating nuclear generating plant subjects us to significant additional risks. These risks include, among others, plant security, environmental regulation and remediation, and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.
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, 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.
Unplanned power plant outages may be costly. Unforeseen maintenance may be required to safely produce electricity or comply with environmental regulations. As a result of unforeseen maintenance, we may be required to make spot market purchases of electricity that exceed our costs of generation. Our financial performance may be negatively affected if we are unable to recover such increased costs.
Our estimates of gas reserves are subject to change. While we cannot provide absolute assurance that our estimates of our Barnett gas reserves are accurate, great care is exercised in utilizing historical information and assumptions to develop reasonable estimates of future production and cash flow. We estimate proved gas reserves and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved gas reserves and cash flows attributable to such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development and exploration activities and prices of gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information we used.
Our ability to utilize production tax credits may be limited. To reduce U.S. dependence on imported oil, the Internal Revenue Code provides production tax credits as an incentive for taxpayers to produce fuels and electricity from alternative sources. We have generated production tax credits from the synfuel, coke
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.
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 business. 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.
Benefits of continuous improvement initiatives could be less than we expect. We have a continuous improvement program that is expected to result in significant cost savings. Actual results achieved through this program could be less than our expectations.
A work interruption may adversely affect us. Unions represent approximately 5,000 of our employees. A union choosing to strike would have an impact on our business. 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.
Item 1B.
Unresolved Staff Comments
None.
Item 3.
Item 3.
Legal Proceedings
We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such
proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.
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 has 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 17 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Item 4.
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 2008.
Part II
Item 5.
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:
At December 31, 2008, there were 163,019,596 shares of our common stock outstanding. These shares were held by a total of 82,706 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. 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 19 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, 2008.
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, 2008:
(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, 2008, repurchases of approximately $725 million of common stock were made under these authorizations. These authorizations provide management with flexibility to pursue share repurchases from time to time and will depend on actual and future asset monetizations, cash flows and investment opportunities.
Item 6.
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
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
DTE Energy is a diversified energy company with 2008 operating revenues in excess of $9 billion and over $24 billion in assets. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.
The following table summarizes our financial results:
The decrease 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
after-tax), including recognition of amounts previously recorded in accumulated other comprehensive income during 2007. Net income in 2008 was also impacted by a gain of $128 million ($81 million after-tax) on the sale of a portion of the Barnett shale properties.
The items discussed below influenced our current financial performance and may affect future results:
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Impacts of national and regional economic conditions on utility operations;
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Effects of weather on utility operations;
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Collectibility of accounts receivable on utility operations;
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Impact of regulatory decisions on utility operations;
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Impact of legislation on utility operations;
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Fluctuations in market demand on coal supply;
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Challenges associated with nuclear fuel;
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Monetization of portions of our Unconventional Gas Production business;
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Discontinuance of planned monetization of a portion of our Power and Industrial Projects business;
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Results in our Energy Trading business;
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Discontinuance of the Synthetic Fuel business; and
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Required environmental and reliability-related capital investments.
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 1.2 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.
Collectibility of Accounts Receivable on Utility Operations - Both utilities continue to experience high levels of past due receivables, which is primarily attributable to economic conditions including high levels of
unemployment and home foreclosures. High energy prices and a lack of adequate levels of assistance for low-income customers have also impacted our accounts receivable.
We have taken actions to manage the level of past due receivables, including customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers.
Our uncollectible accounts expense for the two utilities increased to $213 million in 2008 from $135 million in 2007 and from $123 million in 2006.
The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-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 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. In December 2008, MichCon received authorization to surcharge $34 million, including a $1 million uncollected balance from the 2005 surcharge, beginning in January 2009. We accrue interest income on the outstanding balances.
Impact of Regulatory Decisions on Utility Operations - On December 23, 2008, the MPSC issued 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 a 2.0% average increase in Detroit Edison’s annual revenue requirement for 2009. Included in the approved $84 million increase in revenues was 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:
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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.
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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.
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Terminated the Pension Equalization Mechanism.
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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.
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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, 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 was net of the recovery of costs associated with the Performance Excellence Process. The settlement agreement provided 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 its 2007-2008 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,
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, have 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 $41 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon sold 0.75 Bcf of base gas in 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. 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 the 2009-2010 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.
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:
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2008 Public Act (PA) 286 that reforms Michigan’s utility regulatory framework, including the electric Customer Choice program,
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2008 PA 295 that establishes a renewable portfolio / energy optimization standard and provides a funding mechanism, and
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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.
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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.
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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.
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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
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.
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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 for a separate funding surcharge to pay the cost of those programs. In accordance with the new 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 file 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
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The bill requires electric providers to source 10% of electricity sold to retail customers from renewable energy resources by 2015.
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Qualifying renewable energy resources include wind, biomass, solar, hydro, and geothermal, among others.
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Detroit Edison will be required to have a renewable energy capacity portfolio of 300MW by December 31, 2013 and 600MW by December 31, 2015.
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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.
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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.
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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.
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The bill also provides for a net metering program to be established by MPSC order for on-site customer-owned renewable generation up to 1% of an electric utility’s load.
Energy Optimization Standard
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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.
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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.
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For natural gas sales, the targeted annual savings start at 0.1 percent in 2009 and ramp up to 0.75 percent by 2012.
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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.
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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.
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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 decoupling true-up mechanism that adjusts for sales volumes that are above or below the level reflected in its gas distribution rates.
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By March 2016, the MPSC may suspend the program if it determines the program is no longer cost-effective.
Impact of Increased Market Demand on Coal Supply - Our generating fleet produces approximately 79% of its electricity from coal. Increasing coal demand from domestic and international markets has resulted in volatility and higher prices which are passed to our customers through the PSCR mechanism. The demand and price 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 have 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.
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; 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. We are a party in 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 an on-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. As part of a strategic review of our non-utility operations, we have taken various actions including the sale of certain non-utility businesses.
Gas Midstream
Gas Midstream owns partnership interests in two interstate transmission pipelines and two natural gas storage fields. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We also hold partnership interests in Millennium Pipeline Company which indirectly connects southern New York State to Upper Midwest/Canadian supply, while providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 87 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facilities are high deliverability storage fields having bi-directional interconnections with Vector Pipeline and MichCon providing our customers access to the Chicago, Michigan, other Midwest and Ontario market centers. The pipeline business is expanding and building new pipeline capacity to serve markets in Northeast United States.
Unconventional Gas Production
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in north Texas. We continue to develop our position here, with total leasehold acreage of 62,395 (60,435 acres, net of interest of others). We continue to acquire select positions in active development areas in the Barnett shale to optimize our existing portfolio.
Monetization of Portions of our Unconventional Gas Production Business - In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 75 Bcfe of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale. The Company recognized a cumulative pre-tax gain of $128 million ($81 million after-tax) on the sale during 2008.
We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $96 million in the Barnett shale in 2008 and expect to 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, 2008, we have a series of cash flow hedges for approximately 3.2 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.33 per Mcf.
Texas - Barnett Shale
(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 and 32,083 acres for the years
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 wells are not included in the table above.
(2)
Developed acreage for continuing operations shows a decrease from 2006 to 2007, which reflects the Company’s experience that spacing of wells in the Barnett shale has been reduced over the years. This reduced spacing estimate drives a shift from developed to undeveloped acreage counts. We continue to expand our total position in the western expansion area of the Barnett shale.
(3)
Excludes sold and impaired assets in southern expansion area of the Barnett shale.
(4)
Represents the standardized measure of undiscounted future net cash flows utilizing extensive estimates. The estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include the impact of hedge contracts.
Power and Industrial Projects
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; 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.
Services provided include pulverized coal, petroleum coke and metallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate one gas-fired peaking electric generating plant, two 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 develops, owns and operates landfill gas recovery systems throughout the United States and produces metallurgical coke from three coke batteries. The production of coke from two 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% 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. During 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 are no longer classified as held for 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 pipeline transportation and storage, and power transmission and generating capacity positions. Our customer base is predominantly utilities, local distribution companies, pipelines, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in the recognition 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 pipeline transportation and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary 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.
DISCONTINUED OPERATIONS
Synthetic Fuel
The Synthetic Fuel business was presented as a non-utility segment through the third quarter of 2007. Due to the expiration of synfuel production tax credits at the end of 2007, the Synthetic Fuel business ceased operations and
was classified as a discontinued operation as of December 31, 2007. 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 synfuel operations, we sold interests in all nine of the facilities, representing 91% of the total production capacity. The synthetic fuel plants generated operating losses that were offset by production tax credits.
The value of a production tax credit was adjusted annually by an inflation factor and published annually by the IRS. The value of production tax credits for synthetic fuel was reduced when the Reference Price of a barrel of oil exceeded certain thresholds. The actual tax credit phase-out for 2007 was approximately 67%.
CAPITAL INVESTMENT
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 $6 billion (excluding investments in new generation capacity, if any), including increased environmental requirements and reliability enhancement projects during the period of 2009 through 2013. Our gas utility segment currently expects to invest approximately $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.
OUTLOOK
The next few years will be a period of rapid change for DTE Energy and for the energy industry. Our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth.
Looking forward, we will focus on several areas that we expect will improve future performance:
•
continuing to pursue regulatory stability and investment recovery for our utilities;
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managing the growth of our utility asset base;
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enhancing our cost structure across all business segments;
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managing cash, capital and liquidity to maintain or improve our financial strength;
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improving Electric and Gas Utility customer satisfaction; and
•
investing in businesses that integrate our assets and leverage our skills and expertise.
We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.
RESULTS OF OPERATIONS
Segments realigned - Beginning in the second quarter of 2008, we have realigned our Coal Transportation and Marketing business from the Coal and Gas Midstream segment (now the Gas Midstream segment) to the 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 Notes to Consolidated Financial Statements in Item 8 of this Report for further information on this realignment. The following sections provide a detailed discussion of the operating performance and future outlook of our segments.
(1)
2008 net income of the Unconventional Gas Production segment resulted principally from the gain on the sale of a portion of our Barnett shale properties. 2007 net loss resulted principally from the recognition of losses on hedge contracts associated with the Antrim sale transaction. 2007 net income of the Corporate & Other segment resulted principally from the gain recognized on the Antrim sale transaction. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of this Report.
ELECTRIC UTILITY
Our Electric Utility segment consists of Detroit Edison.
Factors impacting income: Net income increased $14 million in 2008 and decreased $8 million in 2007. The 2008 increase was primarily due to lower expenses for operation and 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.
Gross margin decreased $118 million during 2008 and increased $43 million in 2007. The 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 higher rates attributable to the April 2008 expiration of a rate reduction related to the MPSC show cause proceeding and higher margins due to customers returning from the electric Customer Choice program. The increase in 2007 was attributed to higher margins due to returning sales from electric Customer Choice, the favorable impact of a May 2007 MPSC order related to the 2005 PSCR reconciliation and weather related impacts, partially offset by lower rates resulting primarily from the August 2006 settlement in the MPSC show cause proceeding and the unfavorable impact of a September 2006 MPSC order related to the 2004 PSCR reconciliation. 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:
(1)
Represents fuel costs associated with power plants.
(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.
Operation and maintenance expense decreased $100 million in 2008 and increased $86 million in 2007. The decrease in 2008 was due primarily to lower information systems implementation costs of $60 million, lower benefit expense of $45 million and lower corporate support expenses of $29 million, partially offset by higher uncollectible expenses of $22 million. The increase in 2007 is primarily due to higher 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.
Depreciation and amortization expense decreased $21 million in 2008 and $45 million in 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.
Taxes other than income decreased $45 million in 2008 due to the Michigan Single Business Tax (SBT) expense in 2007, which was replaced with the Michigan Business Tax (MBT) in 2008. The MBT is accounted for in the Income Tax provision.
Asset (gains) losses and reserves, net 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).
Other (income) and deductions expense increased $6 million in 2008 and decreased $17 million in 2007. The 2008 increase is attributable to $15 million of investment losses in a trust utilized for retirement benefits and $3 million 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 recur 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.
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 regulatory and/or legislative solutions. Many of these issues and problems have been addressed by the legislation signed by the Governor of Michigan in October 2008, discussed more fully in the Overview section. Looking forward, additional issues, such as volatility 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 continue 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 $2.8 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.
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; 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. In addition, Detroit Edison is also moving ahead with plans for renewable energy resources and an aggressive energy efficiency program.
The following variables, either individually or in combination, could impact our future results:
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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;
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Economic conditions within Michigan and corresponding impacts on demand for electricity;
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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;
•
Our ability to reduce costs and maximize plant and distribution system performance;
•
Variations in market prices of power, coal and gas;
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Weather, including the severity and frequency of storms;
•
The level of customer participation in the electric Customer Choice program; and
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Any potential new federal and state environmental, renewable energy and energy efficiency requirements.
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 2007. The 2008 and 2007 increases were due primarily to higher gross margins.
Gross margin increased $63 million and $19 million in 2008 and 2007, respectively. The increase in 2008 reflects $49 million from the uncollectible tracking mechanism, $15 million related to the impacts of colder weather, $10 million favorable result of lower lost gas recognized and higher valued gas received as compensation for transportation of third party customer gas, $7 million of 2007 GCR disallowances, and $6 million of appliance repair revenue. The 2008 improvement was partially offset by $19 million of lower storage services revenue and $12 million from customer conservation and lower volumes. 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. Revenues include a component for the cost of gas sold that is recoverable through the GCR mechanism.
Operation and maintenance expense increased $35 million in 2008 and decreased $2 million in 2007. 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 revenues from the uncollectible tracking mechanism included in 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 information systems implementation costs.
Other Asset (gains) losses, net increased $23 million in 2008 and $3 million in 2007. Both increases are primarily attributable to the sale of base gas.
Outlook - 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 GCR and uncollectible true-up mechanisms. We will continue 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:
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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 gas and levels of lost or stolen gas;
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Collectibility of accounts receivable;
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Increases in future expense and contributions to pension and other postretirement plans due to declines in value resulting from market conditions;
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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;
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Variations in market prices of gas;
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Weather;
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Customer conservation;
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Volatility in the short-term storage markets which impact third-party storage revenues;
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Extent and timing of any base gas sales;
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Any potential new federal and state environmental, renewable energy and energy efficiency requirements.
NON-UTILITY OPERATIONS
Gas Midstream
Our Gas Midstream segment consists of our non-utility gas pipelines and storage businesses.
Factors impacting income: Net income increased $4 million and $6 million in 2008 and 2007, respectively. The 2008 increase is due to higher storage revenues related to expansion of capacity and 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 storage revenues and lower expenses due to the Washington 10 restructuring during 2006.
Outlook - Our Gas Midstream business expects to continue its steady growth plan. In April 2008, an additional 7 Bcf of storage capacity was placed in service. Future additions to storage capacity of approximately 3 Bcf will occur over the next few months. Vector Pipeline placed into service its Phase 1 expansion for approximately 200 MMcf/d in November 2007. In addition, Vector Pipeline received FERC approval in June 2008 to build one additional compressor station, which will expand the Vector Pipeline by approximately 100 MMcf/d, with a proposed in-service date of November 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. Both the 2007 and 2009 expansion projects are supported by customers under long-term contracts. Millennium Pipeline was placed in service in December 2008 and currently has nearly 85% of its capacity sold to customers under long-term contracts.
Unconventional Gas Production
Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in northern Texas. In June 2007, we sold our Antrim shale gas exploration and production business in northern Michigan for gross proceeds of $1.262 billion.
In January 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 75 Bcf of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale. We recognized a gain of $128 million ($81 million after-tax) on the sale in 2008.
Factors impacting income: 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 results reflect the recording of $323 million of losses on financial contracts related to expected Antrim gas production and sales through 2013.
Operating revenues increased $276 million in 2008 and decreased $327 million in 2007. The 2007 decrease reflects 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. In conjunction with the Antrim sale, Antrim reclassified amounts held in accumulated other comprehensive income, reducing operating revenues in the 2007 period by $323 million. Excluding the impact of the losses on the Antrim hedges, operating revenues decreased $47 million in 2008 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, net increased $147 million in 2008 due to the gain on sale of Barnett shale core properties offset by $8 million of impairment losses primarily related to leases on unproved acreage that expire in 2009 that we do not anticipate developing due to current economic conditions. The $30 million decrease in 2007 was primarily due to the recording of impairment losses of $27 million in 2007 related to the write-off of unproved properties and the expiration of leases in the southern expansion area of the Barnett shale.
Outlook - We plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We invested approximately $96 million in the Barnett shale in 2008. During 2009, we expect to invest approximately $25 million to drill 15 to 25 new wells and achieve Barnett shale production of approximately 5 to 6 Bcfe of natural gas from our remaining properties, compared with approximately 5 Bcfe in 2008.
Power and Industrial Projects
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation services and marketing; and sell electricity from biomass-fired energy projects.
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.
Operating revenues decreased $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 fee from the sale of an asset we operated for a third party. In 2007, revenues were impacted by higher synfuel related volumes and increases in trading volumes related to both coal and emissions.
Operation and maintenance expense decreased $244 million in 2008 and increased $171 million in 2007. The 2008 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 synfuel related production and higher trading volumes related to coal and emissions.
Depreciation and amortization expense decreased $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.
Other assets (gains) losses, reserves and impairments, net expense decreased $6 million in 2008 and decreased $76 million in 2007. The 2008 decrease is primarily attributable to a loss of approximately $19 million related to the valuation adjustment for the cumulative depreciation and amortization upon reclassification of certain project assets as held and used. Partially offsetting the 2008 loss were gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production. The 2007 decrease is due to impairments recognized in 2006 at natural gas- fired generating plants, long-lived assets at several landfill gas recovery sites and fixed assets and patents at our waste coal recovery business
Other (income) and deductions were higher by $9 million in 2008 due primarily to higher inter-company interest. The 2007 decrease was due primarily 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.
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 supply onsite energy services to the domestic automotive manufacturers who have also been negatively affected by the economic 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 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.
Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional on-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 acquire on-site energy projects and biomass fired generating projects for advantageous prices.
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 pipeline transportation and storage, and power transmission and generating capacity positions.
Factors impacting income: Net income increased $10 million in 2008 and decreased $64 million in 2007.
Gross margin increased $35 million in 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 realized
margin is due to unfavorability of $28 million primarily from our power marketing and transmission optimization strategies, $34 million of unfavorability in our gas storage and full requirements strategies due to falling prices in 2008, offset by $31 million of improvement in our gas trading strategy. The 2007 decrease is attributable to approximately $30 million of unrealized losses for gas contracts related to revisions of valuation estimates for the long-dated portion of our energy contracts and $32 million due to absence of unrealized gains on economic storage hedges and positions in our full requirements strategy. Timing differences from 2005 that largely reversed and favorably impacted 2006 margin resulted in $11 million of realized unfavorability in 2007. Additionally, margins were unfavorably impacted by $13 million of lower realized gains from reduced merchant storage capacity in 2007 and $12 million of unfavorability in realized power positions.
Operation and maintenance expense increased $10 million in 2008 and decreased $7 million in 2007. The 2008 increase is due to higher payroll and incentive costs and allocated corporate costs. The 2007 decrease was due primarily to lower incentive expenses.
Outlook - Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipeline transportation and certain storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. A 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, forwards and swaps. This results in gains and losses that are recognized in different interim and annual accounting periods.
See Capital Resources and Liquidity and Fair Value sections that follow for additional discussion of our trading activities.
CORPORATE & OTHER
Corporate & Other includes various holding company activities and holds certain non-utility debt and energy-related investments.
Factors impacting income: Corporate & Other results decreased by $597 million in 2008 and increased by $563 million in 2007. This is mostly attributable to the 2007 gain on the sale of the Antrim shale gas exploration and production business for approximately $900 million ($580 million after-tax) and variations in inter-company interest.
DISCONTINUED OPERATIONS
Synthetic Fuel
The Company discontinued the operations of our synthetic fuel production facilities 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 income: 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 the final determination of the 2007 IRS reference price and inflation factor in 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.
(1)
Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.
Operating revenues decreased $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 maintenance expense decreased $1,256 million in 2008 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.
Depreciation and amortization expense was lower by $30 million in 2007 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, net decreased $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 reflects the impact of reserve adjustments for the final phase-out percentage and true-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.
The following table displays the various pre-tax components that comprise the determination of synfuel gains and losses in 2008, 2007 and 2006.
(1)
Includes $70 million in 2006, representing our partners’ share of the asset impairment, included in Minority Interest.
Minority interest decreased by $190 million and $63 million in 2008 and 2007, respectively. The 2008 reduction is due to the cessation of operations of our synfuel facilities at December 31, 2007. The 2007 decrease reflects the lower net operating losses in 2007 due to the asset impairment charge we incurred in 2006, partially offset by an increased discount on higher sales levels for 2007.
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 Position FAS 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 2008, our cash requirements were met primarily through operations and from our non-utility monetization program.
Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2009 of up to $1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We incurred environmental expenditures of approximately $270 million in 2008 and we expect over $2.9 billion of future capital expenditures through 2018 to satisfy both existing and proposed new requirements. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.
We expect non-utility capital spending will approximate $175 million to $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 2009 totals approximately $350 million.
Cash from Operating Activities
A majority of our operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.
Cash from operations totaling $1.6 billion in 2008, increased $434 million from the comparable 2007 period. The operating cash flow comparison primarily reflects higher net income, after adjusting for non-cash and non-operating items (depreciation, depletion and amortization, deferred taxes and gains on sales of assets), and cash payments received related to our synfuel program hedges.
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.
Cash from Investing Activities
Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated from plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.
Net cash used for investing activities was approximately $1.5 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.
Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% to 52%, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet.
Net cash used for financing activities was $84 million in 2008, compared to net cash used of approximately $1.5 billion for the same period in 2007. The change was primarily attributable to increased proceeds from the issuance of long-term debt, net of debt redemptions and repurchases, and lower repurchases of 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 a lower level of long-term debt issuances, partially offset by lower debt redemptions.
Outlook
We expect cash flow 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.
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 needs 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 benefit 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 our 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 maintain adequate amounts of liquidity and to meet our future operating cash and capital expenditure needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact earnings and cash flows.
See Notes 11 and 13 of the Notes to Consolidated Financial Statements in Item 8 of this Report.
Contractual Obligations
The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2008:
(1)
Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.
(2)
Includes liabilities for unrecognized tax benefits of $72 million.
(3)
Excludes other long-term liabilities of $182 million not directly derived from contracts or other agreements.
(4)
At December 31, 2008, we met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 for our defined benefit pension plans. We may contribute more than the minimum funding requirements for our pension plans and may also make contributions to our benefit plans and our postretirement benefit plans; however, these amounts are not included in the table above as such amounts are discretionary. Planned funding levels are disclosed in the Critical Accounting Estimates section of MD&A and in Note 18 of the Notes to Consolidated Financial Statements.
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
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.
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
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
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.
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,
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.
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.
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 Position FAS 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).
The subsequent tables contain the following four categories represented by their operating characteristics and key risks:
•
Economic Hedges - Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.
•
Structured Contracts - Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.
•
Proprietary Trading - Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.
•
Other - Primarily represents derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein.
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 reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement.
The following tables provide details on changes in our MTM net asset (or liability) position during 2008:
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.
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.
The table below shows the maturity of our MTM positions:
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Market Price Risk
DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.
The Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. 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
Item 8.
Financial Statements and Supplementary Data
The following consolidated financial statements and schedules are included herein.
Controls and Procedures
(a)
Evaluation of disclosure controls and procedures
Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 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) in Internal 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.
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.
As discussed in Note 8 to the consolidated financial statements, in connection with the required adoption of a new accounting standard, the Company changed its method of accounting for uncertainty in income taxes on January 1, 2007. As discussed in Notes 18 and 19 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans and share based payments, respectively.
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 in Internal Control - Integrated Framework issued 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
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 in Internal Control - Integrated Framework issued 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 in Internal Control - Integrated Framework issued 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
DTE Energy Company
Consolidated Statements of Operations
See Notes to Consolidated Financial Statements
DTE Energy Company
Consolidated Statements of Financial Position
See Notes to Consolidated Financial Statements
DTE Energy Company
Consolidated Statements of Financial Position
See Notes to Consolidated Financial Statements
DTE Energy Company
Consolidated Statements of Cash Flows
See Notes to Consolidated Financial Statements
DTE Energy Company
Consolidated Statements of Changes in Shareholders’ Equity
See Notes to Consolidated Financial Statements
DTE Energy Company
Consolidated Statements of Comprehensive Income
The following table displays comprehensive income:
See Notes to Consolidated Financial Statements
DTE Energy Company
Notes to Consolidated Financial Statements
Note 1 -
SIGNIFICANT ACCOUNTING POLICIES
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 of natural gas to approximately 1.2 million customers throughout Michigan; and
•
Our four non-utility segments are involved in 1) gas pipelines and storage; 2) unconventional gas exploration, development and production; 3) power and industrial projects and coal transportation and marketing; and 4) energy marketing and trading operations.
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.
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
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:
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 Issue No. 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.
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.
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 the last-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
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:
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.
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 an 18-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:
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
The Company records asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and 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 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.
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.
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 2008 follows:
Approximately $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 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 a property-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 costs to sell.
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 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.” 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, 2008 and December 31, 2007 is as follows:
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 2006. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2008
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
were $85 million 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. Our intangible assets related to emission allowances increased to $19 million at December 31, 2008 from $9 million 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 $7 million annually for 2009 through 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.
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 15.
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:
Supplementary cash and non-cash information for the years ended December 31, were as follows:
In connection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent. As a result, the Company entered into a demand financing agreement for up to $50 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). The amounts outstanding under this facility were $26 million and $13 million at December 31, 2008 and 2007, respectively.
See the following notes for other accounting policies impacting the Company’s consolidated financial statements:
DTE Energy Company
Notes to Consolidated Financial Statements - (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. Effective January 1, 2008, the Company adopted SFAS No. 157. As permitted by FASB Staff Position FAS 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 represented a $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 Statement 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 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. At January 1, 2008, the Company elected not 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
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 issued FSP 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 intent and/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 FSP EITF 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 FSP No. 133-1 and FIN 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.
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 FSP FIN 39-1, Amendment of FASB Interpretation No. 39. This FSP 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 is 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 adopted FSP FIN 39-1 as of January 1, 2008. At adoption, the Company chose 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 on the Consolidated Statement of Financial Position at December 31, 2007 as follows:
The total 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 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 promptly improve disclosures by public entities and enterprises until the pending amendments to FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and FASB
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. 132 (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 ending after December 15, 2009. The Company will adopt this FSP on 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 $1.3 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 in EITF 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. In conjunction with the Antrim sale, 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 announced its 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 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, the Company’s 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. During the second quarter of 2008, the Company recorded a loss of $19 million related to the valuation adjustment for the cumulative depreciation and amortization not recorded during the held for sale period. The
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
Consolidated Statements of 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:
Sale of Interest in Barnett Shale Properties
In 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $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 recognized a gain of $128 million ($81 million after-tax) on the sale during 2008.
Synthetic Fuel Business
The Company discontinued the operations of its 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 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
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
Company estimates that its maximum potential liability under these guarantees at December 31, 2008 is $2.9 billion.
As shown in the following table, the Company has reported the business activity of the synthetic fuel business as a discontinued operation. The amounts exclude general corporate overhead costs:
(1)
Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.
NOTE 4 -
OTHER IMPAIRMENTS AND RESTRUCTURING
Other Impairments
Barnett shale
Our Unconventional Gas Production segment recorded pre-tax impairment losses of $8 million and $27 million in 2008 and 2007, respectively. The 2008 impairment related primarily to the write-off of leases that expired or will expire within the next twelve months and are not expected to be developed under current economic conditions. The 2007 impairment consisted of expired leases in Bosque County, which is located in the southern expansion area of the Barnett shale in North Texas. The properties were impaired due to the lack of economic and operating viability of the properties. Impairment losses were recorded within the Other asset (gains) and losses, reserves, and impairments, net line in the Consolidated Statements of Operations.
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.
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 a gas-fired peaking electric generating plant is recorded within the Other (income) and deductions, Other expenses line in the Consolidated Statements of 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.
Restructuring Costs
In 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 incurred costs to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $24 million, $54 million and $102 million of CTA in 2008, 2007 and 2006 as a regulatory asset. The recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Amortization of prior year deferred CTA costs amounted to $16 million in 2008 and $10 million in 2007. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon expects to seek a recovery mechanism in its next rate case expected to be filed in 2009.
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:
NOTE 5 -
REGULATORY MATTERS
Regulation
Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.
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 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.
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:
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
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
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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 costs. The asset will reverse as the deferred items are recognized as benefit expenses in net income. (1)
•
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 costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1)
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.
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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.
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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 - PA 609 of 2002 permits, after MPSC authorization, the recovery of enhanced security costs for an electric generating facility.
•
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 expense true-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 - The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed. (1)
•
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 rates as the related taxable temporary differences reverse and flow through current income tax expense. (1)
DTE Energy Company
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.
•
Pension equalization mechanism - Pension expense refundable to customers representing the difference created from volatility in the pension obligation and amounts recognized pursuant to MPSC authorization.
•
Negative pension offset - MichCon’s negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent MichCon’s pension expense is positive in future years.
•
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.
•
Accrued GCR refund - Liability for the temporary over-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.
•
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.
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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 to 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.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
As part of the settlement agreement, a 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% 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% of the increase in non-fuel revenue to the unrecovered regulatory asset balance. In 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 below the base level of sales of 3,200 GWh. Accordingly, the Company used the resulting additional non-fuel revenue to reduce unrecovered regulatory asset balances related to the RARS mechanism. This reconciliation did not result in 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.
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. Supplements and updates were filed on August 31, 2007 and February 20, 2008.
On December 23, 2008, the MPSC issued 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 2.0% average increase in Detroit Edison’s annual revenue requirement for 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.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
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 $378 million increase in revenues is required to recover the 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 the reduction in territory sales.
In addition, Detroit Edison’s filing made, among other requests, the following proposals:
•
Continued progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;
•
Continued application of an adjustment mechanism to enable the Company to address the costs associated with retail electric customers migrating to and from Detroit Edison’s full service retail electric tariff service;
•
Application of an uncollectible expense true-up mechanism based on the $87 million expense level of uncollectible expenses that occurred during the 12 month period ended June 2008;
•
Continued application of the storm restoration expense recovery mechanism and modification to the line clearance expense recovery mechanism; and
•
Implementation of a revenue decoupling mechanism.
Cost-Based Tariffs for Schools
In January 2009, Detroit Edison filed a required 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 file 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.
Accounting for Costs Related to Enterprise Business Systems
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 certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2008, approximately $26 million of EBS costs have been deferred as a regulatory asset. In the MPSC’s December 2008 order in the 2007 Detroit Edison rate case, the Commission approved the recovery of deferred EBS costs over a 10-year period 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 April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi 2 Enhanced 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
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 expense related to this regulatory asset was approximately $4 million and $3 million 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 RARS. This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS 5-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 5-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-down of RARS-related costs in 2007. As 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 April 2008.
Power Supply Cost Recovery Proceedings
2005 Plan Year - In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval for recovery of an under-collection of approximately $144 million at December 31, 2005 from its commercial and industrial customers. In addition to the 2005 PSCR plan year reconciliation, the filing included 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 on their contributions to pension expense during the subject periods. An order was issued on May 22, 2007 approving a 2005 PSCR under-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 March 2007, Detroit Edison filed its 2006 PSCR reconciliation that sought approval for recovery of an under-collection of approximately $51 million. Included in the 2006 PSCR reconciliation filing was the Company’s PEM reconciliation that reflects a $21 million over-collection which is subject to refund to customers. An MPSC order was issued on April 22, 2008 approving the 2006 PSCR under-collection amount of $51 million and the recovery of this amount as part of the 2007 PSCR factor. In addition, the order approved Detroit Edison’s PEM reconciliation and authorized the Company to refund the $22 million over-recovery, including interest, to customers in May 2008. The refund will be reconciled in the Company’s 2008 PEM reconciliation.
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 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. In
DTE Energy Company
Notes to 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. Also included in the filing was a request for approval of the Company’s emission compliance strategy which included 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) 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.
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.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
Uncollectible Expense True-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. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses totaled $60 million. The true-up mechanism allowed MichCon to recover 90% 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 that 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.
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 showed 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 was 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 the 2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. MPSC Staff and other intervenors 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. In December 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 recorded in 2007. The MPSC authorized MichCon to roll a net over-recovery, inclusive of interest, of $20 million into its 2006-2007 GCR reconciliation. In December 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 the 2006-2007 GCR year. The filing supported a total under-recovery, including interest through March 2007, of $18 million. In
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 the 2006-2007 GCR year. The under-recovery, including interest through March 2007, agreed to under the settlement is $9 million and was included in the 2007-2008 GCR reconciliation. An MPSC order 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 its 2007-2008 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 provided for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provided 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 in August 2007. 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 $41 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon sold 0.75 Bcf of base gas in 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. In June 2008, MichCon filed its GCR reconciliation for the 2007-2008 GCR year. The filing supported a total under-recovery, including interest through March 2008, of $10 million.
2008-2009 Plan Year - In December 2007, MichCon filed its GCR plan case for the 2008-2009 GCR Plan year. MichCon filed for a maximum GCR factor of $8.36 per 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 the 2008-2009 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 the 2009-2010 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 the 2009-2010 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 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 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. In September 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
DTE Energy Company
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
General
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.
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 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, repair and/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 extended through December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts. For multiple terrorism losses caused by acts of terrorism not covered under the TRIA occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 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 $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.
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 $117.5 million could be levied against each licensed nuclear facility, but not more than $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.
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 2008 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 completed by 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 Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.
A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and clean-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.
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 income and 1% in cash equivalents. The debt securities had an average maturity of approximately 5.3 years.
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:
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:
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.
Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $92 million and $22 million of unrealized losses as regulatory assets for the years ended December 31, 2008 and 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 year 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, Detroit Edison recognized impairment charges of $0.2 million, 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
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. We have begun work on an on-site dry cask storage facility which is expected to provide sufficient storage capability for the life of the 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, 2008 was as follows:
*
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.
DTE Energy Company
Notes to Consolidated Financial Statements - (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:
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:
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
Production tax credits earned in prior years but not utilized totaled $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 had received a private letter ruling (PLR) from the Internal Revenue Service (IRS). These PLRs provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.
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 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:
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 $42 million and $28 million at December 31, 2008 and 2007, respectively. The state net operating loss and credit carry-forwards expire from 2009 through 2029. The Company has recorded valuation allowances at December 31, 2008 and 2007 of approximately $42 million and $28 million, respectively, a change of $14 million, with respect to these deferred tax assets. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will
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, 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.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
The Company has $18 million of unrecognized tax benefits at December 31, 2008, that, if recognized, would favorably impact our effective tax rate. During the next 12 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 the Company’s tax returns in various states. Therefore, as of December 31, 2008, the Company believes that it is reasonably possible that there will be a decrease in unrecognized tax benefits of $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, 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 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
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
provides credits for Michigan business investment, compensation, and research and development. The MBT is 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 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 tax 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 to $243 million. The deferred tax liabilities of our regulatory utilities were increased 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.
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
Common Stock
The DTE Energy Board of Directors has authorized the repurchase of up to $1.55 billion of common stock through 2009. Through December 31, 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 stock and/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, 2008 was to restrict approximately $555 million as payments for dividends of total retained earnings of approximately $3 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.
DTE Energy Company
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:
Options to purchase approximately 5 million shares, 2,100 shares, and 100,000 shares of common stock in 2008, 2007 and 2006, respectively, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.
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) of debt outstanding at December 31 were:
(1)
Weighted average interest rates as of December 31, 2008 are shown below the description of each category of debt.
(2)
Detroit Edison Tax Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.
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Notes to Consolidated Financial Statements - (Continued)
Debt Issuances
In 2008, the Company has issued or remarketed the following long-term debt:
(1)
Proceeds were used to pay down short-term debt and for general corporate purposes.
(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.
Debt Retirements and Redemptions
In 2008, the following debt has been retired, through optional redemption or payment at maturity:
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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:
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.
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, 2008, the amount of authorized and unissued stock is as follows:
DTE Energy Company
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. 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 1. DTE Energy, Detroit Edison and MichCon are 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 combined facilities is shown in the following table:
We have other outstanding letters of credit 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, 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 $50 million with its clearing agent. The amount outstanding under this agreement was $26 million and $13 million at December 31, 2008 and 2007, respectively.
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Notes to Consolidated Financial Statements - (Continued)
Detroit Edison terminated a $200 million short-term financing agreement secured by customer accounts receivable in 2008.
NOTE 14 -
CAPITAL AND OPERATING LEASES
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, 2008 were:
Rental expense for operating leases was $49 million in 2008, $60 million in 2007, and $72 million in 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, 2008, were as follows:
DTE Energy Company
Notes to Consolidated Financial Statements - (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.
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:
(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:
(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
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
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.
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 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 Power and Industrial Projects segment. The fair value of all derivatives is included in Derivative assets or liabilities 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. Contracts that are derivatives and meet the normal purchases and sales exemption are 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 2012. These gas-supply 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 operate on-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
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 income/ (loss) will be reclassified to earnings, as the related production affects earnings through 2010. In 2008 and 2007, $0.5 million of after-tax gains and $222 million of after-tax losses, respectively, were reclassified to 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 2009, management estimates reclassifying an after-tax gain of approximately $3 million to 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, unless certain hedge accounting criteria are met.
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 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. Amounts were recorded to Other comprehensive income and reclassified to Operating revenues or Fuel, purchased power and gas expense when the related hedged item impacted earnings.
In 2008 and 2007, $1 million and $7 million, respectively, of after-tax losses were reclassified to earnings. The foreign currency hedge has been fully realized as of December 31, 2008 and therefore, no further earnings impact is expected.
Gas Midstream - These business units are primarily engaged in services related to the transportation, processing and storage of natural gas. These businesses utilize fixed-priced contracts in their marketing and management of their businesses. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.
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, 2008 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.
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 2033. In 2009, the Company estimates reclassifying $4 million of losses to earnings.
NOTE 17 -
COMMITMENTS AND CONTINGENCIES
Environmental
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. Since 2005, EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.4 billion through 2008. The Company estimates Detroit Edison future undiscounted capital expenditures at up to $100 million in 2009 and up to $2.8 billion of additional capital expenditures through 2018 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 2008 in additional capital expenditures to comply with these requirements. However, a January 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 expected to be incurred over the next several years. At December 31, 2008 and 2007, the Company had $12 million 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.
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 2008, the Company spent approximately $2 million investigating and remediating these former MGP sites. As of December 31, 2008 and 2007, the 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 facility in Michigan. The Company expects the projects to be completed by the first half of 2009. The Michigan coke battery facility 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% equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium began commercial operations in December 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 and was fully drawn as of December 31, 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.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
The Company has agreed to guarantee 26% of the borrowing facility and in the event of default by 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. Related to this facility, the Company has also agreed to guarantee 26% of Millennium’s forward-starting interest rate swaps with a notional amount of $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 exposure under our share of Millennium’s forward-starting interest rate swaps. An incremental .25% decrease in the forward interest rate swap rates will increase our exposure by approximately $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 have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post.
The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of December 31, 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, 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 our union employees. The majority of our union employees are under contracts that expire in June and October 2010 and August 2012.
Purchase Commitments
Detroit Edison has an Energy Purchase Agreement to purchase electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison purchased steam through 2008.
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. We purchased approximately $42 million of steam and electricity in each of 2008, 2007 and 2006. We estimate electric purchase commitments from 2009 through 2024 will not exceed $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 sale, Detroit Edison guaranteed bank loans of $13 million that Thermal Ventures II, LP used for capital improvements to the steam heating system. At December 31, 2008 and 2007, the Company had reserves of $13 million related to the bank loan guarantee.
As of December 31, 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 2009 through 2051. The Company also estimates that 2009 capital expenditures will be approximately $1.1 billion. The Company has made certain commitments in connection with expected capital expenditures.
Bankruptcies
The Company purchases and sells electricity, gas, coal, coke and other energy products from and to 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 may have a material effect on the Company’s consolidated 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 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.
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. 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 costs for the period from December 1, 2007 to December 31, 2008. Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.
Detroit Edison and MichCon received approval from the MPSC to record the impact of the adoption of the SFAS 158 provisions related to funded status as a regulatory 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, 2008 and December 31, 2007 are based on measurement dates of December 31, 2008 and November 30, 2007, respectively.
Pension Plan Benefits
The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover substantially all employees. The plans provide traditional retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. In addition, certain represented and non-represented employees are covered under cash balance provisions that determine benefits on annual employer contributions and interest credits. The Company also maintains supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by DTE Energy’s other retirement plans.
The Company’s policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. In December 2008, the Company contributed $100 million to the pension plans. Also, the Company contributed $50 million to the pension plans in January 2009. The Company anticipates making up to a $250 million contribution to its pension plans in 2009.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
Net pension cost includes the following components:
Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the Consolidated Statement of Financial Position at December 31:
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
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:
At December 31, 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:
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
The Company employs a formal process in determining the long-term rate of return for various asset classes. Management reviews historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness.
The 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. and non-U.S. stocks, growth and value investment styles, and large and small market capitalizations. Other assets such as private equity and hedge funds are used to enhance long-term returns while improving portfolio diversification. Derivatives may be utilized in a risk controlled manner, to potentially increase the portfolio beyond the market value of invested assets 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:
The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2008 were as follows:
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 and 2006.
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 2008, the Company made cash contributions of $116 million to its postretirement benefit plans. In January 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 an additional $130 million contribution to its VEBA trusts in 2009.
Net postretirement cost includes the following components:
Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the Consolidated Statement of Financial Position at December 31:
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:
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 $29 million and increased the accumulated benefit obligation by $241 million at December 31, 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 $26 million and would have decreased the accumulated benefit obligation by $238 million at December 31, 2008.
At December 31, 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 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.
At December 31, 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:
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:
The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2008 were as follows:
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 -
STOCK-BASED COMPENSATION
The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units to employees and members of its Board of Directors. Key provisions of the stock incentive program are:
•
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
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:
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 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 vest ratably over a three-year period.
Stock option activity was as follows:
As of December 31, 2008, the weighted average remaining contractual life for the exercisable shares is 4.46 years. As of December 31, 2008, 1,247,222 options were non-vested. During 2008, 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 $6.12, respectively. The intrinsic value of options exercised for the years ended December 31, 2008, 2007 and 2006 was $1 million, $16 million, and $6 million, respectively. Total option expense recognized during 2008, 2007 and 2006 was $3 million, $4 million and $6 million, respectively.
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:
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:
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.
Stock Awards
Stock awards granted under the plan are restricted for varying periods, 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.
Stock award activity for the periods ended December 31 was:
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, 2008:
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 closing stock price market value. The settlement of the award is at based on the closing price at the settlement date.
The Company recorded compensation expense as follows:
(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.
The following table summarizes the Company’s performance share activity for the period ended December 31, 2008:
Unrecognized Compensation Costs
As of December 31, 2008, there was $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 1.33 years.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
The tax benefit realized for tax deductions related to the Company’s stock incentive plan totaled $13 million for the period ended December 31, 2008. Approximately $1.6 million, $1.4 million, and $1.6 million of compensation cost was capitalized as part of fixed assets during 2008, 2007, and 2006, respectively.
NOTE 20 -
SEGMENT AND RELATED INFORMATION
Beginning in the second quarter of 2008, the Company realigned its Coal Transportation and Marketing business from the Coal and Gas Midstream segment (now the Gas Midstream segment) to the Power and Industrial Projects segment, due to changes in how financial information is evaluated and resources are allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:
Electric Utility
•
The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 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 consists of gas pipelines and storage businesses;
•
Unconventional Gas Production is engaged in unconventional gas project development and production;
•
Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, biomass energy projects and coal transportation and marketing; and
•
Energy Trading primarily consists of energy marketing and trading operations.
Corporate & Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.
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:
Financial data of the business segments follows:
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
(1)
Net income of the Unconventional Gas production segment in 2008 reflects the gain recognized on the sale of Barnett shale properties. Operating revenues and net loss of the Unconventional Gas Production segment in 2007 reflect the recognition of losses on hedge contracts associated with the Antrim sale transaction. Net Income of the Corporate & Other segment in 2007 results principally from the gain recognized on the Antrim sale transaction. See Note 3.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
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.
DTE Energy Company
Notes to Consolidated Financial Statements - (Continued)
(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. See Note 3.
(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.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
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.
Item 9B.
Other Information
Part III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Item 11.
Executive Compensation
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Item 14.
Principal Accountant Fees and Services
Other than the information provided under Executive Officers of DTE Energy in Part I, information required by Part III (Items 10, 11, 12, 13 and 14) of this Form 10-K is incorporated by reference from DTE Energy’s definitive Proxy Statement for its 2009 Annual Meeting of Common Shareholders to be held April 30, 2009. The Proxy Statement will be filed with the Securities and Exchange Commission, pursuant to Regulation 14A, not later than 120 days after the end of our fiscal year covered by this report on Form 10-K, all of which information is hereby incorporated by reference in, and made part of, this Form 10-K, except that the information required by Item 10 with respect to executive officers of the Registrant is included in Part I of this Report.
Part IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
DTE Energy Company
Schedule II - Valuation and Qualifying Accounts
(1)
Collection of accounts previously written off and balances previously held for sale of $4 million.
(2)
Uncollectible accounts written off.
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)
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.
Date: February 27, 2009