10-K 1 k12475e10vk.txt ANNUAL REPORT FOR FISCAL YEAR ENDED DECEMBER 31, 2006 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 -------------- FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION REGISTRANT; STATE OF INCORPORATION; IRS EMPLOYER FILE NUMBER ADDRESS; AND TELEPHONE NUMBER IDENTIFICATION NO. ----------- ----------------------------------- ------------------ 1-9513 CMS Energy Corporation 38-2726431 (A Michigan Corporation) One Energy Plaza, Jackson, Michigan 49201 (517) 788-0550 1-5611 Consumers Energy Company 38-0442310 (A Michigan Corporation) One Energy Plaza, Jackson, Michigan 49201 (517) 788-0550
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE REGISTRANT TITLE OF CLASS ON WHICH REGISTERED ---------- -------------- --------------------- CMS Energy Corporation Common Stock, $.01 par value New York Stock Exchange CMS ENERGY TRUST I 7.75% Quarterly Income New York Stock Exchange Preferred Securities CONSUMERS ENERGY Preferred Stocks, $100 par New York Stock Exchange COMPANY value: $4.16 Series, $4.50 Series
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. CMS ENERGY CORPORATION: Yes [X] No [ ] CONSUMERS ENERGY COMPANY: Yes [X] No [ ] Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. CMS ENERGY CORPORATION: Yes [ ] No [X] CONSUMERS ENERGY COMPANY: Yes [ ] No [X] Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Exchange Act Rule 12b-2). CMS ENERGY CORPORATION: Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] CONSUMERS ENERGY COMPANY: Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X] Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2). CMS ENERGY CORPORATION: Yes [ ] No [X] CONSUMERS ENERGY COMPANY: Yes [ ] No [X] The aggregate market value of CMS Energy voting and non-voting common equity held by non-affiliates was $2.853 billion for the 220,508,564 CMS Energy Common Stock shares outstanding on June 30, 2006 based on the closing sale price of $12.94 for CMS Energy Common Stock, as reported by the New York Stock Exchange on such date. There were 223,255,864 shares of CMS Energy Common Stock outstanding on February 20, 2007. On February 20, 2007, CMS Energy held all voting and non-voting common equity of Consumers. Documents incorporated by reference: CMS Energy's proxy statement and Consumers' information statement relating to the 2007 annual meeting of shareholders to be held May 18, 2007, is incorporated by reference in Part III, except for the compensation and human resources committee report and audit committee report contained therein. ================================================================================ CMS Energy Corporation And Consumers Energy Company Annual Reports on Form 10-K to the Securities and Exchange Commission For the Year Ended December 31, 2006 This combined Form 10-K is separately filed by CMS Energy Corporation and Consumers Energy Company. Information in this combined Form 10-K relating to each individual registrant is filed by such registrant on its own behalf. Consumers Energy Company makes no representation regarding information relating to any other companies affiliated with CMS Energy Corporation other than its own subsidiaries. TABLE OF CONTENTS
PAGE ---- Glossary ............................................................... 3 PART I: Item 1. Business....................................................... 9 Item 1A. Risk Factors................................................... 26 Item 1B. Unresolved Staff Comments...................................... 33 Item 2. Properties..................................................... 33 Item 3. Legal Proceedings.............................................. 33 Item 4. Submission of Matters to a Vote of Security Holders............ 37 PART II: Item 5. Market for Registrant's Common Equity, Related Stockholder 38 Matters and Issuer Purchases of Equity Securities.............. Item 6. Selected Financial Data........................................ 38 Item 7. Management's Discussion and Analysis of Financial Condition and 38 Results of Operations.......................................... Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 39 Item 8. Financial Statements and Supplementary Data.................... 40 Item 9. Changes in and Disagreements With Accountants on Accounting and CO-1 Financial Disclosure........................................... Item 9A. Controls and Procedures........................................ CO-1 Item 9B. Other Information.............................................. CO-6 PART III: Item 10. Directors, Executive Officers and Corporate Governance......... CO-7 Item 11. Executive Compensation......................................... CO-7 Item 12. Security Ownership of Certain Beneficial Owners and Management CO-8 Related Stockholder Matters.................................... Item 13. Certain Relationships and Related Transactions, and Director CO-8 Independence................................................... Item 14. Principal Accountant Fees and Services......................... CO-8 PART IV: Item 15. Exhibits, Financial Statement Schedules........................ CO-8
2 GLOSSARY Certain terms used in the text and financial statements are defined below ABATE.................... Association of Businesses Advocating Tariff Equity ABO...................... Accumulated Benefit Obligation. The liabilities of a pension plan based on service and pay to date. This differs from the Projected Benefit Obligation that is typically disclosed in that it does not reflect expected future salary increases. AFUDC.................... Allowance for Funds Used During Construction ALJ...................... Administrative Law Judge AMT...................... Alternative minimum tax AOCI..................... Accumulated Other Comprehensive Income AOCL..................... Accumulated Other Comprehensive Loss APB...................... Accounting Principles Board APB Opinion No. 18....... APB Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock" APT...................... Australian Pipeline Trust ARO...................... Asset retirement obligation Attorney General......... Michigan Attorney General Bay Harbor............... a residential/commercial real estate area located near Petoskey, Michigan. In 2002, CMS Energy sold its interest in Bay Harbor. bcf...................... One billion cubic feet of gas Big Rock................. Big Rock Point nuclear power plant, owned by Consumers Bluewater Pipeline....... Bluewater Pipeline, a 24.9-mile pipeline that extends from Marysville, Michigan to Armada, Michigan Board of Directors....... Board of Directors of CMS Energy Btu...................... British thermal unit CEO...................... Chief Executive Officer CFO...................... Chief Financial Officer CFTC..................... Commodity Futures Trading Commission CKD...................... Cement Kiln Dust Clean Air Act............ Federal Clean Air Act, as amended CMS Energy............... CMS Energy Corporation, the parent of Consumers and Enterprises CMS Energy Common Stock or common stock........ Common stock of CMS Energy, par value $.01 per share CMS Electric and Gas..... CMS Electric and Gas Company, a subsidiary of Enterprises CMS ERM.................. CMS Energy Resource Management Company, formerly CMS MST, a subsidiary of Enterprises CMS Field Services....... CMS Field Services, Inc., formerly a wholly owned subsidiary of CMS Gas Transmission. The sale of this subsidiary closed in July 2003. CMS Gas Transmission..... CMS Gas Transmission Company, a wholly owned subsidiary of Enterprises CMS Generation........... CMS Generation Co., a wholly owned subsidiary of Enterprises CMS Holdings............. CMS Midland Holdings Company, a subsidiary of Consumers CMS International Ventures............... CMS International Ventures LLC, a subsidiary of Enterprises CMS Midland.............. Midland Cogeneration Venture Group II, LLC, successor to CMS Midland Inc., formerly a subsidiary of Consumers that had a 49 percent ownership interest in the MCV Partnership
3 CMS Midland Holdings Company................ CMS Midland Holdings Company, a subsidiary of Consumers that has a 46 percent ownership interest in First Midland Limited Partnership and a 35 percent lessor interest in the MCV Facility CMS MST.................. CMS Marketing, Services and Trading Company, a wholly owned subsidiary of Enterprises, whose name was changed to CMS ERM effective January 2004 CMS Oil and Gas.......... CMS Oil and Gas Company, formerly a subsidiary of Enterprises Consumers................ Consumers Energy Company, a subsidiary of CMS Energy Court of Appeals......... Michigan Court of Appeals CPEE..................... Companhia Paulista de Energia Eletrica, in which CMS International Ventures owns a 94 percent interest CT Mendoza............... The 540 MW natural gas-fired power plant located in Argentina, in which CMS International Ventures owns a 92.6 percent interest Customer Choice Act...... Customer Choice and Electricity Reliability Act, a Michigan statute enacted in June 2000 DCCP..................... Defined Company Contribution Plan Detroit Edison........... The Detroit Edison Company, a non-affiliated company DIG...................... Dearborn Industrial Generation, LLC, an indirect wholly owned subsidiary of CMS Energy DOE...................... U.S. Department of Energy DOJ...................... U.S. Department of Justice Dow...................... The Dow Chemical Company, a non-affiliated company DTE Energy............... DTE Energy Company, a non-affiliated company EISP..................... Executive Incentive Separation Plan EITF..................... Emerging Issues Task Force EITF Issue No. 02-03..... Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities El Chocon................ The 1,200 MW hydro power plant located in Argentina, in which CMS Generation holds a 17.2 percent ownership interest Ensenada................. The 128 MW natural gas-fired power plant located in Argentina, in which CMS International Ventures owns 100 percent interest Entergy.................. Entergy Corporation, a non-affiliated company Enterprises.............. CMS Enterprises Company, a subsidiary of CMS Energy EPA...................... U.S. Environmental Protection Agency EPS...................... Earnings per share Exchange Act............. Securities Exchange Act of 1934, as amended FASB..................... Financial Accounting Standards Board FASB Interpretation No. 46(R).................. Revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities FERC..................... Federal Energy Regulatory Commission FIN 47................... FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations FIN 48................... FASB Interpretation No. 48, Uncertainty in Income Taxes First Mortgage Bond Indenture.............. The indenture dated as of September 1, 1945 between Consumers and JPMorgan Chase Bank, N.A. (ultimate successor to City Bank Farmers Trust Company), as Trustee, and as amended and supplemented FMB...................... First Mortgage Bonds FMLP..................... First Midland Limited Partnership, a partnership that holds a lessor interest in the MCV Facility and an indirect subsidiary of Consumers
4 FSP...................... FASB Staff Position FTR...................... Financial transmission right GAAP..................... Generally Accepted Accounting Principles GasAtacama............... GasAtacama Holding Limited, a limited liability partnership that manages GasAtacama S.A., which includes an integrated natural gas pipeline and electric generating plant located in Argentina and Chile and Atacama Finance Company, in which CMS International Ventures owns a 50 percent interest GCR...................... Gas cost recovery Goldfields............... A pipeline business located in Australia, in which CMS Energy formerly held a 39.7 percent ownership interest GVK...................... GVK Facility, a 250 MW gas fired power plant located in South Central India, in which CMS Generation formerly held a 33 percent interest GWh...................... Gigawatt-hour IPP...................... Independent Power Producer IRS...................... Internal Revenue Service ISFSI.................... Independent Spent Fuel Storage Installation ITC...................... Income tax credit Jorf Lasfar.............. The 1,356 MW coal-fueled power plant in Morocco, jointly owned by CMS Generation and ABB Energy Ventures, Inc., in which CMS Generation owns a 50 percent interest Jubail................... A 240 MW natural gas cogeneration power plant located in Saudi Arabia, in which CMS Generation owns a 25 percent interest kWh...................... Kilowatt-hour (a unit of energy equal to one thousand watt hours) Loy Yang................. The 2,000 MW brown coal fueled Loy Yang A power plant and an associated coal mine in Victoria, Australia, in which CMS Generation formerly held a 50 percent ownership interest Ludington................ Ludington pumped storage plant, jointly owned by Consumers and Detroit Edison Marysville............... CMS Marysville Gas Liquids Company, a Michigan corporation and a former subsidiary of CMS Gas Transmission that held a 100 percent interest in Marysville Fractionation Partnership and a 51 percent interest in St. Clair Underground Storage Partnership mcf...................... One thousand cubic feet of gas MCV Facility............. A natural gas-fueled, combined-cycle cogeneration facility operated by the MCV Partnership MCV GP II................ Midland Cogeneration Venture Group II, LLC which is the successor of CMS Midland, Inc. MCV Partnership.......... Midland Cogeneration Venture Limited Partnership in which Consumers has a 49 percent interest through CMS Midland, Inc. MCV PPA.................. The Power Purchase Agreement between Consumers and the MCV Partnership with a 35-year term commencing in March 1990, as amended, and as interpreted by the Settlement Agreement dated as of January 1, 1999 between the MCV Partnership and Consumers. MD&A..................... Management's Discussion and Analysis MDEQ..................... Michigan Department of Environmental Quality METC..................... Michigan Electric Transmission Company, LLC which is owned by ITC Holding Corporation, a company that operates electric transmission facilities through a wholly owned subsidiary, including the transmission system within Detroit Edison's territory
5 Midwest Energy Market.... An energy market developed by the MISO to provide day-ahead and real-time market information and centralized dispatch for market participants MISO..................... Midwest Independent Transmission System Operator, Inc. MMBtu.................... Million British thermal unit Moody's.................. Moody's Investors Service, Inc. MPSC..................... Michigan Public Service Commission MRV...................... Market-Related Value of Plan assets MSBT..................... Michigan Single Business Tax MW....................... Megawatt (a unit of power equal to one million watts) MWh...................... Megawatt-hour (a unit of energy equal to one million watt hours) NEIL..................... Nuclear Electric Insurance Limited, an industry mutual insurance company owned by member utility companies Neyveli.................. CMS Generation Neyveli Ltd, a 250 MW lignite- fired power station located in Neyveli, Tamil Nadu, India, in which CMS International Ventures holds a 50 percent interest NMC...................... Nuclear Management Company LLC, formed in 1999 by Northern States Power Company (now Xcel Energy Inc.), Alliant Energy, Wisconsin Electric Power Company, and Wisconsin Public Service Company to operate and manage nuclear generating facilities owned by the four utilities NOL...................... Net Operating Loss NRC...................... Nuclear Regulatory Commission NYMEX.................... New York Mercantile Exchange OCI...................... Other Comprehensive Income OPEB..................... Postretirement benefit plans other than pensions for retired employees Palisades................ Palisades nuclear power plant, which is owned by Consumers Panhandle................ Panhandle Eastern Pipe Line Company, including its subsidiaries Trunkline, Pan Gas Storage, Panhandle Storage, and Panhandle Holdings. Panhandle was a wholly owned subsidiary of CMS Gas Transmission. The sale of this subsidiary closed in June 2003. Parmelia................. A business located in Australia comprised of a pipeline, processing facilities, and a gas storage facility, a former subsidiary of CMS Gas Transmission PCB...................... Polychlorinated biphenyl Peabody Energy........... Peabody Energy Corporation, a non-affiliated company Pension Plan............. The trusteed, non-contributory, defined benefit pension plan of Panhandle, Consumers and CMS Energy Price Anderson Act....... Price Anderson Act, enacted in 1957 as an amendment to the Atomic Energy Act of 1954, as revised and extended over the years. This act stipulates between nuclear licensees and the U.S. government the insurance, financial responsibility, and legal liability for nuclear accidents. PSCR..................... Power supply cost recovery PUHCA.................... Public Utility Holding Company Act PURPA.................... Public Utility Regulatory Policies Act of 1978 RCP...................... Resource Conservation Plan ROA...................... Retail Open Access S&P...................... Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, Inc. SAB No. 107.............. Staff Accounting Bulletin No. 107, Share-Based Payment
6 SEC...................... U.S. Securities and Exchange Commission Section 10d(4) Regulatory Asset.................. Regulatory asset as described in Section 10d(4) of the Customer Choice Act, as amended Securitization........... A financing method authorized by statute and approved by the MPSC which allows a utility to sell its right to receive a portion of the rate payments received from its customers for the repayment of Securitization bonds issued by a special purpose entity affiliated with such utility SENECA................... Sistema Electrico del Estado Nueva Esparta C.A., a subsidiary of Enterprises SERP..................... Supplemental Executive Retirement Plan SFAS..................... Statement of Financial Accounting Standards SFAS No. 5............... SFAS No. 5, "Accounting for Contingencies" SFAS No. 13.............. SFAS No. 13, "Accounting for Leases" SFAS No. 71.............. SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 87.............. SFAS No. 87, "Employers' Accounting for Pensions" SFAS No. 88.............. SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" SFAS No. 98.............. SFAS No. 98, "Accounting for Leases" SFAS No. 106............. SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS No. 109............. SFAS No. 109, "Accounting for Income Taxes" SFAS No. 115............. SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" SFAS No. 123(R).......... SFAS No. 123 (revised 2004), "Share-Based Payment" SFAS No. 132(R).......... SFAS No. 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits" SFAS No. 133............. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted" SFAS No. 143............. SFAS No. 143, "Accounting for Asset Retirement Obligations" SFAS No. 144............. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" SFAS No. 157............. SFAS No. 157, "Fair Value Measurement" SFAS No. 158............. 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)" Shuweihat................ A power and desalination plant of Shuweihat CMS International Power Company, in which CMS Generation holds a 20 percent interest SLAP..................... Scudder Latin American Power Fund Southern Union........... Southern Union Company, a non-affiliated company SRLY..................... Separate Return Limitation Year Stranded Costs........... Costs incurred by utilities in order to serve their customers in a regulated monopoly environment, which may not be recoverable in a competitive environment because of customers leaving their systems and ceasing to pay for their costs. These costs could include owned and purchased generation and regulatory assets. Superfund................ Comprehensive Environmental Response, Compensation and Liability Act
7 Takoradi................. A 200 MW open-cycle combustion turbine crude oil power plant located in Ghana, in which CMS Generation owns a 90 percent interest TAQA..................... Abu Dhabi National Energy Company, a subsidiary of Abu Dhabi Water and Electricity Authority, CMS Generation's partner in the Taweelah and Shuweihat projects Taweelah................. Al Taweelah A2, a power and desalination plant of Emirates CMS Power Company, in which CMS Generation holds a 40 percent interest TGM...................... A natural gas transportation and pipeline business located in Argentina, in which CMS International Ventures owns a 20 percent interest TGN...................... A natural gas transportation and pipeline business located in Argentina, in which CMS Gas Transmission owns a 23.54 percent interest TRAC..................... Terminal Rental Adjustment Clause, a provision of a leasing agreement which permits or requires the rental price to be adjusted upward or downward by reference to the amount realized by the lessor under the agreement upon sale or other disposition of formerly leased property Trunkline................ CMS Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle Holdings, LLC Trust Preferred Securities............. Securities representing an undivided beneficial interest in the assets of statutory business trusts, the interests of which have a preference with respect to certain trust distributions over the interests of either CMS Energy or Consumers, as applicable, as owner of the common beneficial interests of the trusts Union.................... Utility Workers Union of America, AFL-CIO VEBA Trusts.............. VEBA employees' beneficiary association trusts accounts established to specifically set aside employer contributed assets to pay for future expenses of the OPEB plan
8 PART I ITEM 1. BUSINESS GENERAL CMS ENERGY CMS Energy was formed in Michigan in 1987 and is an energy holding company operating through subsidiaries in the United States and in selected markets around the world. Its two principal subsidiaries are Consumers and Enterprises. Consumers is a public utility that provides natural gas and/or electricity to almost 6.5 million of Michigan's 10 million residents and serves customers in all 68 of the state's Lower Peninsula counties. Enterprises, through various subsidiaries and affiliates, is engaged in diversified energy businesses in the United States and in selected markets around the world. See ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- EXECUTIVE OVERVIEW. CMS Energy's consolidated operating revenue was $6.810 billion in 2006, $6.288 billion in 2005 and $5.472 billion in 2004. CMS Energy operates in three business segments -- electric utility, gas utility, and enterprises. See BUSINESS SEGMENTS later in this Item 1 for further discussion of each segment. CONSUMERS Consumers was formed in Michigan in 1968 and is the successor to a corporation organized in Maine in 1910 that conducted business in Michigan from 1915 to 1968. Consumers serves companies operating in the automotive, metal, chemical and food products industries as well as a diversified group of other industries. In 2006, Consumers served 1.8 million electric customers and 1.7 million gas customers. Consumers' consolidated operations account for a majority of CMS Energy's total assets and income, as well as a substantial portion of its operating revenue. Consumers' consolidated operating revenue was $5.721 billion in 2006, $5.232 billion in 2005 and $4.711 billion in 2004. Consumers' rates and certain other aspects of its business are subject to the jurisdiction of the MPSC, the FERC, and the NRC, as described in CMS ENERGY AND CONSUMERS REGULATION later in this Item 1. CONSUMERS' PROPERTIES -- GENERAL: Consumers owns its principal properties in fee, except that most electric lines and gas mains are located in public roads or on land owned by others and are accessed by Consumers pursuant to easements and other rights. Almost all of Consumers' properties are subject to the lien of its First Mortgage Bond Indenture. For additional information on Consumers' properties see BUSINESS SEGMENTS -- Consumers Electric Utility -- Electric Utility Properties, and -- Consumers Gas Utility -- Gas Utility Properties, below. BUSINESS SEGMENTS CMS ENERGY FINANCIAL INFORMATION For further information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to all of CMS Energy's business segments and international and domestic operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION and CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS and NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CONSUMERS FINANCIAL INFORMATION For further information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to Consumers' electric and gas utility operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION and CONSUMERS' CONSOLIDATED FINANCIAL STATEMENTS and NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 9 CONSUMERS ELECTRIC UTILITY ELECTRIC UTILITY OPERATIONS Consumers' electric utility operating revenue was $3.302 billion in 2006, $2.701 billion in 2005 and $2.586 billion in 2004. Consumers' electric utility operations include the generation, purchase, distribution and sale of electricity. At year-end 2006, it was authorized to provide service in 60 of the 68 counties of Michigan's Lower Peninsula. Principal cities served include Battle Creek, Flint, Grand Rapids, Jackson, Kalamazoo, Midland, Muskegon and Saginaw. Consumers' electric utility customer base includes a mix of residential, commercial and diversified industrial customers, the largest segment of which is the automotive industry (which comprises 5 percent of CMS Energy's revenues). Consumers' electric utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of such customers is not reasonably likely to have a material adverse effect on its financial condition. Consumers' electric utility operations are seasonal. The summer months usually increase demand for electric energy, principally due to the use of air conditioners and other cooling equipment, thereby affecting revenues. In 2006, Consumers' electric sales were 37 billion kWh and retail open access deliveries were 1 billion kWh, for total electric deliveries of 38 billion kWh. In 2005, Consumers' electric sales were 35 billion kWh and retail open access deliveries were 4 billion kWh, for total electric deliveries of 39 billion kWh. Consumers' 2006 summer peak demand was 8,657 MW excluding retail open access loads and 8,883 MW including retail open access loads. For the 2005-06 winter period, Consumers' peak demand was 5,752 MW excluding retail open access loads and 6,123 MW including retail open access loads. Based on its summer 2006 forecast, Consumers carried an 11 percent reserve margin target. However, as a result of higher than forecasted peak loads, Consumers' ultimate reserve margin was 6 percent compared to 15 percent in 2005. Currently, Consumers owns or controls capacity necessary to supply approximately 108 percent of projected firm summer peak load for summer 2007 and is in the process of securing the additional capacity needed to meet its summer 2007 reserve margin target of 11 percent (111 percent of projected firm summer peak load). The ultimate use of the reserve margin will depend primarily on summer weather conditions, the level of retail open access requirements being served by others during the summer, and any unscheduled plant outages. 10 ELECTRIC UTILITY PROPERTIES GENERATION: At December 31, 2006, Consumers' electric generating system consisted of the following:
2006 2006 NET SUMMER NET GENERATION SIZE AND YEAR DEMONSTRATED (MILLIONS NAME AND LOCATION (MICHIGAN) ENTERING SERVICE CAPABILITY (MW) OF KWH) ---------------------------- --------------------- --------------- ---------- COAL GENERATION J H Campbell 1 & 2 -- West Olive........ 2 Units, 1962-1967 615 4,358 J H Campbell 3 -- West Olive............ 1 Unit, 1980 765(a) 3,712 D E Karn -- Essexville.................. 2 Units, 1959-1961 515 3,587 B C Cobb -- Muskegon.................... 2 Units, 1956-1957 312 1,844 J R Whiting -- Erie..................... 3 Units, 1952-1953 328 2,378 J C Weadock -- Essexville............... 2 Units, 1955-1958 306 1,865 ----- ------ Total coal generation..................... 2,841 17,744 ----- ------ OIL/GAS GENERATION B C Cobb -- Muskegon.................... 3 Units, 1999-2000(b) 183 14 D E Karn -- Essexville.................. 2 Units, 1975-1977 1,276 179 ----- ------ Total oil/gas generation.................. 1,459 193 ----- ------ HYDROELECTRIC Conventional Hydro Generation........... 13 Plants, 1906-1949 74 485 Ludington Pumped Storage................ 6 Units, 1973 955(c) (426)(d) ----- ------ Total hydroelectric....................... 1,029 59 ----- ------ NUCLEAR GENERATION Palisades -- South Haven................ 1 Unit, 1971 778 5,904 ----- ------ GAS/OIL COMBUSTION TURBINE Generation.............................. 7 Plants, 1966-1971 345 16 ----- ------ Total owned generation.................... 6,452 23,916 PURCHASED AND INTERCHANGE POWER Capacity................................ 2,762(e) ----- Total..................................... 9,214 =====
-------------- (a) Represents Consumers' share of the capacity of the J H Campbell 3 unit, net of 6.69 percent (ownership interests of the Michigan Public Power Agency and Wolverine Power Supply Cooperative, Inc.). (b) Cobb 1-3 are retired coal-fired units that were converted to gas-fired. Units were placed back into service in the years indicated. (c) Represents Consumers' share of the capacity of Ludington. Consumers and Detroit Edison have 51 percent and 49 percent undivided ownership, respectively, in the plant. (d) Represents Consumers' share of net pumped storage generation. This facility electrically pumps water during off-peak hours for storage to later generate electricity during peak-demand hours. (e) Includes 1,240 MW of purchased contract capacity from the MCV Facility. In 2006, through the Midwest Energy Market, long-term purchase contracts, options, spot market and other seasonal purchases, Consumers purchased up to 2,762 MW of net capacity from others, which amounted to 32 percent of Consumers' total system requirements. DISTRIBUTION: Consumers' distribution system includes: - 383 miles of high-voltage distribution radial lines operating at 120 kilovolts and above; 11 - 4,197 miles of high-voltage distribution overhead lines operating at 23 kilovolts and 46 kilovolts; - 17 subsurface miles of high-voltage distribution underground lines operating at 23 kilovolts and 46 kilovolts; - 55,525 miles of electric distribution overhead lines; - 9,586 subsurface miles of underground distribution lines; and - substations having an aggregate transformer capacity of 22,705,360 kilovoltamperes. Consumers is interconnected to METC, a member of MISO. METC owns an interstate high-voltage electric transmission system located in Michigan and is interconnected with neighboring utilities as well as other transmission systems. FUEL SUPPLY: As shown below, Consumers generates electricity principally from coal and nuclear fuel.
MILLIONS OF KWH ------------------------------------------ POWER GENERATED 2006 2005 2004 2003 2002 --------------- ------ ------ ------ ------ ------ Coal......................................... 17,744 19,711 18,810 20,091 19,361 Nuclear...................................... 5,904 6,636 5,346 6,151 6,358 Oil.......................................... 48 225 193 242 347 Gas.......................................... 161 356 38 129 354 Hydro........................................ 485 387 445 335 387 Net pumped storage........................... (426) (516) (538) (517) (486) ------ ------ ------ ------ ------ Total net generation......................... 23,916 26,799 24,294 26,431 26,321 ====== ====== ====== ====== ======
The cost of all fuels consumed, shown below, fluctuates with the mix of fuel burned.
COST PER MILLION BTU -------------------------------------- FUEL CONSUMED 2006 2005 2004 2003 2002 ------------- ----- ----- ------ ----- ----- Coal............................................ $2.09 $1.78 $ 1.43 $1.33 $1.34 Oil............................................. 8.68 5.98 4.68 3.92 3.49 Gas............................................. 8.92 9.76 10.07 7.62 3.98 Nuclear......................................... 0.24 0.34 0.33 0.34 0.35 All Fuels(a).................................... 1.72 1.64 1.26 1.16 1.19
-------------- (a) Weighted average fuel costs. Consumers has four generating plant sites that burn coal. In 2006, these plants produced a combined total of 17,744 million kWh of electricity, which represents 75 percent of Consumers' 23,648 million kWh baseload supply, the capacity used to serve a constant level of customer demand. These plants burned 8.9 million tons of coal in 2006. On December 31, 2006, Consumers had on hand a 53-day supply of coal. Consumers enters into a number of purchase obligations that represent normal business operating contracts. These contracts are used to assure an adequate supply of goods and services necessary to operate its business and to minimize exposure to market price fluctuations. Consumers believes that these future costs are prudent and reasonably assured of recovery in future rates. Consumers has entered into coal supply contracts with various suppliers and associated rail transportation contracts for its coal-fired generating stations. Under the terms of these agreements, Consumers is obligated to take physical delivery of the coal and make payment based upon the contract terms. Consumers' coal supply contracts expire through 2010, and total an estimated $515 million. Its coal transportation contracts expire through 2009, and total an estimated $214 million. Long-term coal supply contracts have accounted for approximately 60 to 90 percent of Consumers' annual coal requirements over the last 10 years. Consumers believes that, at present, it will be within the historic 60 to 90 percent range. At December 31, 2006, Consumers had future unrecognized commitments to purchase capacity and energy under long-term power purchase agreements with various generating plants. These contracts require monthly capacity payments based on the plants' availability or deliverability. These payments for 2007 through 2030 total an 12 estimated $15.815 billion. This amount may vary depending upon plant availability and fuel costs. Consumers is obligated to pay capacity charges based only on the amount of capacity available at a given time, whether or not power is delivered to Consumers. Consumers owns Palisades, an operating nuclear power plant located near South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers transferred its authority to operate Palisades to NMC. During 2006, Palisades' net generation was 5,904 million kWh, constituting 25 percent of Consumers' baseload supply. Palisades' nuclear fuel supply responsibilities are under NMC's control as agent for Consumers. New fuel contracts are being written as NMC agreements. Consumers/NMC currently have sufficient contracts in place to supply 100 percent of the uranium concentrates and conversion services and 100 percent of the enrichment services requirements for the 2007 reload. A contract for uranium concentrates is in place to supply approximately 6 percent of the 2008 reload requirements. Two contracts for conversion services are in place to supply approximately 39 percent of the 2008 reload requirements and a contract for enrichment services is in place to supply approximately 32 percent of the 2008 reload requirements. Consumers has a contract for nuclear fuel fabrication services in place for reloads in 2007 through 2013. In July 2006, Consumers reached an agreement to sell Palisades to Entergy and for Entergy to assume ownership and responsibility for the Big Rock ISFSI. As part of the transaction, Entergy will sell Consumers 100 percent of Palisades' output up to its current capacity of 798 MW under a 15-year power purchase agreement. The sale is subject to various regulatory approvals, including but not limited to the MPSC's approval of the power purchase agreement, the FERC's approval for Entergy to sell power to Consumers under the power purchase agreement and the NRC's approval of the transfer of the operating license to Entergy. Consumers expects to complete the sale in 2007. The Nuclear Waste Policy Act of 1982 made the federal government responsible for the permanent disposal of spent nuclear fuel and high-level radioactive waste by 1998. The DOE has not arranged for storage facilities and it does not expect to receive spent nuclear fuel for storage in 2007 or the near term. Palisades currently has spent nuclear fuel that exceeds its temporary on- site storage pool capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved steel and concrete vaults known as "dry casks." For additional information on disposal of nuclear fuel and Consumers' use of dry casks, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS. CONSUMERS GAS UTILITY GAS UTILITY OPERATIONS Consumers' gas utility operating revenue was $2.374 billion in 2006, $2.483 billion in 2005 and $2.081 billion in 2004. Consumers' gas utility operations purchase, transport, store, distribute and sell natural gas. As of December 31, 2006, it was authorized to provide service in 47 of the 68 counties in Michigan's Lower Peninsula. Principal cities served include Bay City, Flint, Jackson, Kalamazoo, Lansing, Pontiac and Saginaw, as well as the suburban Detroit area, where nearly 900,000 of Consumers' gas customers are located. Consumers' gas utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of such customers is not reasonably likely to have a material adverse effect on its financial condition. Consumers' gas utility operations are seasonal. Consumers injects natural gas into storage during the summer months for use during the winter months when the demand for natural gas is higher. Peak demand usually occurs in the winter due to colder temperatures and the resulting increased demand for heating fuels. In 2006, deliveries of natural gas sold by Consumers and by other sellers who deliver natural gas to customers (including the MCV Partnership) through Consumers' pipeline and distribution network totaled 313 bcf. 13 GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system located throughout Michigan's Lower Peninsula consists of: - 26,295 miles of distribution mains; - 1,671 miles of transmission lines; - 7 compressor stations with a total of 162,000 installed horsepower; and - 15 gas storage fields with an aggregate storage capacity of 308 bcf and a working storage capacity of 143 bcf. GAS SUPPLY: In 2006, Consumers purchased 67 percent of the gas it delivered from United States producers and 26 percent from Canadian producers. Authorized suppliers in the gas customer choice program supplied the remaining 7 percent of gas that Consumers delivered. Consumers' firm gas transportation agreements are with ANR Pipeline Company, Great Lakes Gas Transmission, L.P., Trunkline Gas Co., Panhandle Eastern Pipe Line Company, and Vector Pipeline. Consumers uses these agreements to deliver gas to Michigan for ultimate deliveries to market. Consumers' firm transportation and city gate arrangements are capable of delivering over 95 percent of Consumers' total gas supply requirements. As of December 31, 2006, Consumers' portfolio of firm transportation from pipelines to Michigan is as follows:
VOLUME (DEKATHERMS/DAY) EXPIRATION ---------------- ---------- ANR Pipeline Company.................................. 50,000 March 2017 Great Lakes Gas Transmission, L.P. ................... 100,000 March 2007 Great Lakes Gas Transmission, L.P (starting 04/01/07)........................................... 100,000 March 2011 Great Lakes Gas Transmission, L.P. ................... 50,000 March 2017 Trunkline Gas Co. .................................... 290,000 October 2008 Panhandle Eastern Pipe Line Company (starting 04/01/07)........................................... 50,000 October 2007 Panhandle Eastern Pipe Line Company (starting 04/01/08)........................................... 50,000 October 2008 Panhandle Eastern Pipe Line Company................... 50,000 October 2008 Vector Pipeline....................................... 50,000 March 2007 Vector Pipeline (starting 04/01/07)................... 50,000 March 2012
Consumers purchases the balance of its required gas supply under incremental firm transportation contracts, firm city gate contracts, and as needed, interruptible transportation contracts. The amount of interruptible transportation service and its use varies primarily with the price for such service and the availability and price of the spot supplies being purchased and transported. Consumers' use of interruptible transportation is generally in off- peak summer months and after Consumers has fully utilized the services under the firm transportation agreements. ENTERPRISES Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international energy businesses including independent power production, electric distribution, and natural gas transmission, storage and processing. Enterprises' operating revenue was $1.135 billion in 2006, $1.110 billion in 2005 and $808 million in 2004. See ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- EXECUTIVE OVERVIEW. NATURAL GAS TRANSMISSION CMS Gas Transmission was formed in 1988 and owns, develops and manages domestic and international natural gas facilities. In 2006, CMS Gas Transmission's operating revenue was $18 million. In June 2003, CMS Gas Transmission sold Panhandle to Southern Union Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union Panhandle Corp. purchased all of Panhandle's outstanding capital 14 stock for approximately $582 million in cash and 3.15 million shares of Southern Union common stock. Southern Union Panhandle Corp. also assumed approximately $1.166 billion in debt. In July 2003, CMS Gas Transmission completed the sale of CMS Field Services to Cantera Natural Gas, Inc. for gross cash proceeds of approximately $113 million, subject to post closing adjustments, and a $50 million face value note of Cantera Natural Gas, Inc. The note is payable to CMS Energy for up to $50 million subject to the financial performance of the Fort Union and Bighorn natural gas gathering systems from 2004 through 2008. In August 2004, CMS Gas Transmission sold its interest in Goldfields and its Parmelia business, a discontinued operation, to APT for A$204 million (approximately $147 million in U.S. dollars). A $45 million ($29 million after- tax) gain on the sale of Goldfields includes a $9 million ($6 million after-tax) foreign currency translation gain. A $10 million ($6 million after-tax) gain on the sale of Parmelia includes a $3 million ($2 million after-tax) foreign currency translation loss. NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of 265 miles of gathering and transmission pipelines located in the state of Michigan, with a daily capacity of 0.75 bcf. At December 31, 2006, CMS Gas Transmission had nominal processing capabilities of approximately 0.33 bcf per day of natural gas in Michigan. Enterprises has entered into a binding letter of intent to sell these assets. At December 31, 2006, CMS Gas Transmission had ownership interests in the following international pipelines:
LOCATION OWNERSHIP INTEREST (%) MILES OF PIPELINES -------- ---------------------- ------------------ Argentina.......................................... 23.5 3,362 Argentina-to-Brazil................................ 20 262 Argentina-to-Chile................................. 50 707
Enterprises has entered into a binding letter of intent to sell its interest in the Argentina-to-Brazil pipeline, and CMS Energy has announced that it will conduct an auction sale in 2007 to sell its interest in the Argentina- to-Chile pipeline. The remaining pipelines in Argentina are subject to a potential sale to the government of Argentina. INDEPENDENT POWER PRODUCTION CMS Generation was formed in 1986. It invests in, acquires, develops, constructs and operates non-utility power generation plants in the United States and abroad. In 2006, the independent power production business segment's operating revenue was $540 million. INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2006, CMS Energy had ownership interests in operating independent power plants totaling 8,809 gross MW or 4,308 net MW (net MW reflects that portion of the gross capacity in relation to CMS Energy's ownership interest). In 2007, Enterprises plans to exit the international marketplace. In 2007, Enterprises entered into a definitive purchase and sale agreement or a binding letter of intent to sell its ownership interests in its power production properties in the Middle East, Africa, India and Argentina. CMS Energy announced that it will conduct an auction sale in 2007 to sell its interests in its power production facilities in Chile and Jamaica. 15 The following table details CMS Energy's interest in independent power plants as of year-end 2006:
PERCENTAGE OF GROSS CAPACITY UNDER LONG-TERM OWNERSHIP INTEREST GROSS CAPACITY CONTRACT LOCATION FUEL TYPE (%) (MW) (%) -------- --------- ------------------ -------------- --------------- California.................... Wood 37.8 36 100 Connecticut................... Scrap tire 100 31 0 Michigan...................... Coal 50 70 100 Michigan...................... Natural gas 100 710 42 Michigan...................... Natural gas 100 224 0 Michigan...................... Wood 50 40 100 Michigan...................... Wood 50 38 100 New York...................... Hydro 17.3 14 100 North Carolina................ Wood 50 50 100 Oklahoma...................... Natural gas 6.25 124 100 ----- DOMESTIC TOTAL........... 1,337 ----- Argentina..................... Hydro 17.2 1,320 20(a) Argentina..................... Natural gas 98.5 128 57 Argentina..................... Natural gas/oil 92.6 597 45 Chile......................... Natural gas 50 720 100 Ghana......................... Crude oil 90 224(b) 100 India......................... Coal 50 250 100 Jamaica....................... Diesel 42.3 63 100 Morocco....................... Coal 50 1,356 100(c) Kingdom of Saudi Arabia....... Natural gas 25 250 100 United Arab Emirates.......... Natural gas 40 777 100 United Arab Emirates.......... Natural gas 20 1,500 100 Venezuela..................... Gas turbine/diesel 87 287 (d) ----- INTERNATIONAL TOTAL......... 7,472 ----- TOTAL DOMESTIC AND INTERNATIONAL............... 8,809 =====
-------------- (a) El Chocon sells its power primarily on a spot market basis; however, it has a high dispatch rate due to low cost. The El Chocon facility is held pursuant to a 30-year possession agreement. (b) Conversion of the Takoradi power plant from single-cycle to combined-cycle with an increase in gross capacity from 224 MW to 341 MW has been delayed. (c) The Jorf Lasfar facility is held pursuant to a right of possession agreement with the Moroccan state-owned Office National de l'Electricite. (d) SENECA is a combined generation/distribution utility that produces power for its sole use. For information on capital expenditures, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- CAPITAL RESOURCES AND LIQUIDITY AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (FINANCINGS AND CAPITALIZATION). OIL AND GAS EXPLORATION AND PRODUCTION CMS Energy used to own an oil and gas exploration and production company. In October 2002, CMS Energy completed its exit from the oil and gas exploration and production business. 16 ENERGY RESOURCE MANAGEMENT In 2003, CMS ERM closed its Houston, Texas office and in 2004, CMS ERM changed its name from CMS Marketing, Services and Trading Company to CMS Energy Resource Management Company. CMS ERM concentrates on the purchase and sale of energy commodities in support of CMS Energy's generating facilities. In March 2004, CMS ERM discontinued its natural gas retail program as customer contracts expired. In 2006, CMS ERM marketed approximately 44 bcf of natural gas and 1,938 GWh of electricity. Its operating revenue was $334 million in 2006, $589 million in 2005 and $381 million in 2004. INTERNATIONAL ENERGY DISTRIBUTION In October 2001, CMS Energy discontinued the operations of its international energy distribution business. In 2002, CMS Energy discontinued new development outside North America, which included closing all non-U.S. development offices. In 2003, due to the uncertainty of executing an asset sale on acceptable terms and conditions, CMS Energy reclassified SENECA, which is its energy distribution business in Venezuela, and CPEE, which is its energy distribution business in Brazil, to continuing operations. In February 2007, CMS Energy entered into a memorandum of understanding to sell SENECA. CMS Energy has announced that it will conduct an auction sale in 2007 to sell its interest in CPEE. CMS ENERGY AND CONSUMERS REGULATION CMS Energy is a public utility holding company that was previously exempt from registration under PUHCA of 1935. PUHCA of 1935 was repealed by the Energy Policy Act of 2005 and replaced by PUHCA of 2005, effective February 8, 2006. CMS Energy, Consumers and their subsidiaries are subject to regulation by various federal, state, local and foreign governmental agencies, including those described below. MICHIGAN PUBLIC SERVICE COMMISSION Consumers is subject to the MPSC's jurisdiction, which regulates public utilities in Michigan with respect to retail utility rates, accounting, utility services, certain facilities and various other matters. The MPSC also has rate jurisdiction over several limited liability companies in which CMS Gas Transmission has ownership interests. These companies own, or will own, and operate intrastate gas transmission pipelines. The Attorney General, ABATE, and the MPSC staff typically intervene in MPSC electric- and gas-related proceedings concerning Consumers. For many years, most significant MPSC orders affecting Consumers have been appealed. Certain appeals from the MPSC orders are pending in the Court of Appeals and the Michigan Supreme Court. RATE PROCEEDINGS: In 2005, the MPSC issued an order that established the electric authorized rate of return on common equity at 11.15 percent. In 2006, the MPSC issued an order that established the gas authorized rate of return on common equity at 11.00 percent. MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the retail electric and gas utility businesses has undergone significant changes. In 2000, the Michigan Legislature enacted the Customer Choice Act. The Customer Choice Act provides that as of January 2002, all electric customers have the choice to buy generation service from an alternative electric supplier. The Customer Choice Act also imposes rate reductions, rate freezes and rate caps, which expired at the end of 2005. For additional information regarding the Customer Choice Act, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING. Consumers transports the natural gas commodity that is sold to some customers by competitors like gas producers, marketers and others. Pursuant to a gas customer choice program that Consumers implemented, as of April 2003 all of Consumers' gas customers were eligible to select an alternative gas commodity supplier. Consumers' current GCR mechanism allows it to recover from its customers all prudently incurred costs to purchase natural gas and transport it to Consumers' facilities. For additional information, see ITEM 8. FINANCIAL 17 STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- CONSUMERS' GAS UTILITY RATE MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- GAS RATE MATTERS. FEDERAL ENERGY REGULATORY COMMISSION The FERC has exercised limited jurisdiction over several independent power plants in which CMS Generation has ownership interests, as well as over CMS ERM and DIG. Among other things, FERC jurisdiction relates to the acquisition, operation and disposal of certain assets and facilities and to the service provided and rates charged. The FERC also has limited jurisdiction over CMS Energy with respect to certain acquisitions of assets and other holding company matters. Some of Consumers' gas business is also subject to regulation by the FERC, including a blanket transportation tariff pursuant to which Consumers can transport gas in interstate commerce. The FERC also regulates certain aspects of Consumers' electric operations including compliance with FERC accounting rules, wholesale rates, operation of licensed hydro-electric generating plants, transfers of certain facilities, and corporate mergers and issuance of securities. The Energy Policy Act of 2005 has modified the FERC's traditional responsibilities in a number of ways, which will affect both Consumers and Enterprises. Among other things, the new law includes repeal of PUHCA of 1935, streamlined electric transmission siting rules, measures designed to promote wholesale competition, certain investment incentives and mandatory electric supply reliability planning. The FERC is currently in the process of establishing standards for ensuring a more reliable system of providing electricity throughout North America through the increased regulation of generation owners and operators, load serving entities and others. NUCLEAR REGULATORY COMMISSION Under the Atomic Energy Act of 1954, as amended, and the Energy Reorganization Act of 1974, Consumers is subject to the jurisdiction of the NRC with respect to the design, construction, operation and decommissioning of its nuclear power plants. Consumers is also subject to NRC jurisdiction with respect to certain other uses of nuclear material. These and other matters concerning Consumers' nuclear plants are more fully discussed in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT AND -- NUCLEAR PLANT DECOMMISSIONING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- OTHER ELECTRIC CONTINGENCIES -- THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT AND -- NUCLEAR PLANT DECOMMISSIONING. OTHER REGULATION The Secretary of Energy regulates the importation and exportation of natural gas and has delegated various aspects of this jurisdiction to the FERC and the DOE's Office of Fossil Fuels. Pipelines owned by system companies are subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulates the safety of gas pipelines. Consumers is also subject to the Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum pipelines. 18 CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE CMS Energy, Consumers and their subsidiaries are subject to various federal, state and local regulations for environmental quality, including air and water quality, waste management, zoning and other matters. CMS Energy has significant possible liability for its obligations associated with Bay Harbor. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. Consumers has installed and is currently installing modern emission controls at its electric generating plants and has converted and is converting electric generating units to burn cleaner fuels. Consumers expects that the cost of future environmental compliance, especially compliance with clean air laws, will be significant because of EPA regulations and proposed regulations regarding nitrogen oxide, particulate-related emissions, and mercury. These regulations will require Consumers to make significant capital expenditures. Consumers is in the process of closing older ash disposal areas at two plants. Construction, operation, and closure of a modern solid waste disposal area for ash can be expensive, because of strict federal and state requirements. In order to significantly reduce ash field closure costs, Consumers has worked with others to use bottom ash and fly ash as part of temporary and final cover for ash disposal areas instead of native materials, in cases where such use of bottom ash and fly ash is compatible with environmental standards. To reduce disposal volumes, Consumers sells coal ash for use as a Portland cement replacement in concrete products, as a filler for asphalt, as feedstock for the manufacture of Portland cement and for other environmentally compatible uses. The EPA has announced its intention to develop new nationwide standards for ash disposal areas. Consumers intends to work through industry groups to help ensure that any such regulations require only the minimum cost necessary to adhere to standards that are consistent with protection of the environment. Consumers' electric generating plants must comply with rules that significantly reduce the number of fish killed by plant cooling water intake systems. Consumers is studying options to determine the most cost-effective solutions for compliance. Like most electric utilities, Consumers has PCB in some of its electrical equipment. During routine maintenance activities, Consumers identified PCB as a component in certain paint, grout and sealant materials at the Ludington Pumped Storage facility. Consumers removed and replaced part of the PCB material. Consumers has proposed a plan to the EPA to deal with the remaining materials and is waiting for a response from the EPA. Certain environmental regulations affecting CMS Energy and Consumers include, but are not limited to, the Clean Air Act Amendments of 1990 and Superfund. Superfund can require any individual or entity that may have owned or operated a disposal site, as well as transporters or generators of hazardous substances that were sent to such site, to share in remediation costs for the site. CMS Energy's and Consumers' current insurance program does not extend to cover the risks of certain environmental cleanup costs or environmental damages, such as claims for air pollution, damage to sites owned by CMS Energy or Consumers, and for some past PCB contamination and for some long-term storage or disposal of pollutants. For additional information concerning environmental matters, including estimated capital expenditures to reduce nitrogen oxide related emissions, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- ELECTRIC ENVIRONMENTAL ESTIMATES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- ELECTRIC ENVIRONMENTAL ESTIMATES. CMS ENERGY AND CONSUMERS COMPETITION ELECTRIC COMPETITION Consumers' electric utility business experiences actual and potential competition from many sources, both in the wholesale and retail markets, as well as in electric generation, electric delivery and retail services. 19 In the wholesale electricity markets, Consumers competes with other wholesale suppliers, marketers and brokers. Electric competition in the wholesale markets increased significantly since 1996 due to FERC Order 888. While Consumers is still active in wholesale electricity markets, wholesale for resale transactions by Consumers generated an immaterial amount of Consumers' 2006 revenues from electric utility operations. Consumers believes future loss of wholesale for resale transactions will be insignificant. Price is the principal method of competition for electric generation services. The Customer Choice Act gives all electric customers the right to buy generation service from an alternative electric supplier. In June 2004, the MPSC granted Consumers recovery of implementation costs incurred for the Electric Customer Choice program. In November 2004, the MPSC adopted a mechanism pursuant to the Customer Choice Act to provide for recovery of stranded costs that occur when customers leave Consumers' system to purchase electricity from alternative electric suppliers. In January 2006, the MPSC approved cost-based retail open access distribution tariffs. A significant decrease in retail electric competition occurred in 2005 due to changes in market conditions, including increased uncertainty and volatility in fuel commodity prices. Energy market volatility continued into 2006. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This amount represents a decrease of 46 percent compared to December 31, 2005, and is 3 percent of Consumers' total distribution load. It is difficult to predict future ROA customer trends. In addition to retail electric customer choice, Consumers has competition or potential competition from: - industrial customers relocating all or a portion of their production capacity outside Consumers' service territory for economic reasons; - municipalities owning or operating competing electric delivery systems; - customer self-generation; and - adjacent utilities that extend lines to customers in contiguous service territories. Consumers addresses this competition by monitoring activity in adjacent areas and enforcing compliance with MPSC and FERC rules, providing non-energy services, and providing tariff-based incentives that support economic development. Consumers offers non-energy revenue services to electric customers, municipalities and other utilities in an effort to offset costs. These services include engineering and consulting, construction of customer-owned distribution facilities, equipment sales (such as transformers), power quality analysis, energy management services, meter reading and joint construction for phone and cable. Consumers faces competition from many sources, including energy management services companies, other utilities, contractors, and retail merchandisers. CMS ERM, a non-utility electric subsidiary, continues to focus on optimizing CMS Energy's independent power production portfolio. CMS Energy's independent power production business, another non-utility electric subsidiary, faces competition from generators, marketers and brokers, as well as other utilities marketing power at lower power prices on the wholesale market. For additional information concerning electric competition, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES. GAS COMPETITION Competition has existed for the past decade in various aspects of Consumers' gas utility business, and is likely to increase. Competition traditionally comes from other gas suppliers taking advantage of direct access to Consumers' customers and from alternate fuels and energy sources, such as propane, oil and electricity. INSURANCE CMS Energy and its subsidiaries, including Consumers, maintain insurance coverage similar to comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and 20 exclusions that might not fully compensate CMS Energy for all losses. A portion of each loss is generally assumed by CMS Energy in the form of deductibles and self-insured retentions that, in some cases, are substantial. As CMS Energy renews its policies it is possible that some of the insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets. For a discussion of nuclear insurance coverage, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS. For a discussion of environmental insurance coverage, see ITEM 1. BUSINESS -- CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE. EMPLOYEES CMS ENERGY As of December 31, 2006, CMS Energy and its wholly owned subsidiaries, including Consumers, had 8,640 full-time equivalent employees. Included in the total are 3,624 employees who are covered by union contracts. CONSUMERS As of December 31, 2006, Consumers and its subsidiaries had 8,026 full-time equivalent employees. Included in the total are 3,314 full-time operating, maintenance and construction employees and 309 full-time and part-time call center employees who are represented by the Utility Workers Union of America. CMS ENERGY EXECUTIVE OFFICERS (AS OF FEBRUARY 1, 2007)
NAME AGE POSITION PERIOD ---- --- -------- ------ David W. Joos......... 53 President and Chief Executive Officer of CMS Energy 2004-Present Chairman of the Board, Chief Executive Officer of Enterprises 2003-Present President, Chief Operating Officer of CMS Energy 2001-2004 Chief Executive Officer of Consumers 2004-Present President, Chief Operating Officer of Consumers 2001-2004 President, Chief Operating Officer of Enterprises 2001-2003 Director of CMS Energy 2001-Present Director of Consumers 2001-Present Director of Enterprises 2000-Present
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NAME AGE POSITION PERIOD ---- --- -------- ------ Thomas J. Webb........ 54 Executive Vice President, Chief Financial Officer of CMS Energy 2002-Present Executive Vice President, Chief Financial Officer of Consumers 2002-Present Executive Vice President, Chief Financial Officer of Enterprises 2002-Present Executive Vice President, Chief Financial Officer of CMS Generation Co. 2006-Present Executive Vice President of CMS Energy 2002 Executive Vice President of Consumers 2002 Director of Enterprises 2002-Present Director of CMS Generation 2003-Present Executive Vice President, Chief Financial Officer of Panhandle Eastern Pipe Line Company 2002-2003 James E. Brunner*..... 54 Senior Vice President and General Counsel of CMS Energy 11/2006-Present Senior Vice President and General Counsel of Consumers 11/2006-Present Senior Vice President of Enterprises 2006-Present Senior Vice President of CMS Generation 2006-Present Director of Enterprises 2006-Present Senior Vice President, General Counsel and Chief Compliance Officer of CMS Energy 5/2006-11/2006 Senior Vice President, General Counsel and Chief Compliance Officer of Consumers 5/2006-11/2006 Senior Vice President, General Counsel and Interim Chief Compliance Officer of Consumers 2/2006-5/2006 Senior Vice President and General Counsel of CMS Energy 2/2006-5/2006 Senior Vice President and General Counsel of Consumers 2/2006-5/2006 Vice President and General Counsel of Consumers 7/2004-2/2006 Vice President of Consumers 2004 John M. Butler**...... 42 Senior Vice President of CMS Energy 6/2006-Present Senior Vice President of Consumers 6/2006-Present Senior Vice President of Enterprises 6/2006-Present Senior Vice President of CMS Generation 6/2006-Present David G. Mengebier.... 49 Senior Vice President and Chief Compliance Officer of CMS Energy 11/2006-Present Senior Vice President and Chief Compliance Officer of Consumers 11/2006-Present Senior Vice President of Enterprises 2003-Present Senior Vice President of CMS Energy 2001-11/2006 Senior Vice President of Consumers 2001-11/2006
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NAME AGE POSITION PERIOD ---- --- -------- ------ Thomas W. Elward...... 58 President, Chief Operating Officer of Enterprises 2003-Present President, Chief Executive Officer of CMS Generation 2002-Present Director of Enterprises 2003-Present Director of CMS Generation 2002-Present Senior Vice President of Enterprises 2002-2003 John G. Russell....... 49 President and Chief Operating Officer of Consumers 2004-Present Executive Vice President and President -- Electric & Gas of Consumers 7/2004-10/2004 Executive Vice President, President and Chief Executive Officer -- Electric of Consumers 2001-2004 Glenn P. Barba........ 41 Vice President, Controller and Chief Accounting Officer of CMS Energy 2003-Present Vice President, Controller and Chief Accounting Officer of Consumers 2003-Present Vice President, Chief Accounting Officer of Enterprises 2003-Present Vice President and Controller of Consumers 2002-2003
-------------- * From 1993 until July of 2004, Mr. Brunner was Assistant General Counsel of Consumers. ** From 2002 until 2004, Mr. Butler was Global Compensation and Benefits Resource Center Director at The Dow Chemical Company and from 2004 until June of 2006, Mr. Butler was Human Resources Director, Manufacturing and Engineering at The Dow Chemical Company. There are no family relationships among executive officers and directors of CMS Energy. The present term of office of each of the executive officers extends to the first meeting of the Board of Directors after the next annual election of Directors of CMS Energy (scheduled to be held on May 18, 2007). CONSUMERS EXECUTIVE OFFICERS (AS OF FEBRUARY 1, 2007)
NAME AGE POSITION PERIOD ---- --- -------- ------ David W. Joos......... 53 President and Chief Executive Officer of CMS Energy 2004-Present Chairman of the Board, Chief Executive Officer of Enterprises 2003-Present President, Chief Operating Officer of CMS Energy 2001-2004 Chief Executive Officer of Consumers 2004-Present President, Chief Operating Officer of Consumers 2001-2004 President, Chief Operating Officer of Enterprises 2001-2003 Director of CMS Energy 2001-Present Director of Consumers 2001-Present Director of Enterprises 2000-Present
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NAME AGE POSITION PERIOD ---- --- -------- ------ Thomas J. Webb........ 54 Executive Vice President, Chief Financial Officer of CMS Energy 2002-Present Executive Vice President, Chief Financial Officer of Consumers 2002-Present Executive Vice President, Chief Financial Officer of Enterprises 2002-Present Executive Vice President, Chief Financial Officer of CMS Generation 2006-Present Executive Vice President of CMS Energy 2002 Executive Vice President of Consumers 2002 Director of Enterprises 2002-Present Director of CMS Generation 2003-Present Executive Vice President, Chief Financial Officer of Panhandle Eastern Pipe Line Company 2002-2003 James E. Brunner*..... 54 Senior Vice President and General Counsel of CMS Energy 11/2006-Present Senior Vice President and General Counsel of Consumers 11/2006-Present Senior Vice President of Enterprises 2006-Present Senior Vice President of CMS Generation 2006-Present Director of Enterprises 2006-Present Senior Vice President, General Counsel and Chief Compliance Officer of CMS Energy 5/2006-11/2006 Senior Vice President, General Counsel and Chief Compliance Officer of Consumers 5/2006-11/2006 Senior Vice President, General Counsel and Interim Chief Compliance Officer of Consumers 2/2006-5/2006 Senior Vice President and General Counsel of CMS Energy 2/2006-5/2006 Senior Vice President and General Counsel of Consumers 2/2006-5/2006 Vice President and General Counsel of Consumers 7/2004-2/2006 Vice President of Consumers 2004 John M. Butler**...... 42 Senior Vice President of CMS Energy 6/2006-Present Senior Vice President of Consumers 6/2006-Present Senior Vice President of Enterprises 6/2006-Present Senior Vice President of CMS Generation 6/2006-Present David G. Mengebier.... 49 Senior Vice President and Chief Compliance Officer of CMS Energy 11/2006-Present Senior Vice President and Chief Compliance Officer of Consumers 11/2006-Present Senior Vice President of Enterprises 2003-Present Senior Vice President of CMS Energy 2001-11/2006 Senior Vice President of Consumers 2001-11/2006
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NAME AGE POSITION PERIOD ---- --- -------- ------ John G. Russell....... 49 President and Chief Operating Officer of Consumers 2004-Present Executive Vice President and President -- Electric & Gas of Consumers 7/2004-10/2004 Executive Vice President, President and Chief Executive Officer -- Electric of Consumers 2001-2004 Robert A. Fenech...... 59 Senior Vice President of Consumers 1997-Present William E. Garrity.... 58 Senior Vice President of Consumers 2005-Present Vice President of Consumers 1999-2005 Frank Johnson......... 58 Senior Vice President of Consumers 2001-Present President, Chief Executive Officer of CMS Electric and Gas 2000-2002 Paul N. Preketes...... 57 Senior Vice President of Consumers 1999-Present Glenn P. Barba........ 41 Vice President, Controller and Chief Accounting Officer of CMS Energy 2003-Present Vice President, Controller and Chief Accounting Officer of Consumers 2003-Present Vice President, Chief Accounting Officer of Enterprises 2003-Present Vice President and Controller of Consumers 2002-2003
-------------- * From 1993 until July of 2004, Mr. Brunner was Assistant General Counsel of Consumers. ** From 2002 until 2004, Mr. Butler was Global Compensation and Benefits Resource Center Director at The Dow Chemical Company and from 2004 until June of 2006, Mr. Butler was Human Resources Director, Manufacturing and Engineering at The Dow Chemical Company. There are no family relationships among executive officers and directors of Consumers. The present term of office of each of the executive officers extends to the first meeting of the Board of Directors after the next annual election of Directors of Consumers (scheduled to be held on May 18, 2007). AVAILABLE INFORMATION CMS Energy's internet address is www.cmsenergy.com. You can access free of charge on our Web site all of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act. Such reports are available as soon as practical after they are electronically filed with the SEC. Also on our Web site are our: - Corporate Governance Principles; - Codes of Conduct (Code of Business Conduct and Ethics); and - Board Committee Charters (including the Audit Committee, the Compensation and Human Resources Committee, the Finance Committee and the Governance and Public Responsibility Committee). We will provide this information in print to any shareholder who requests it. You may also read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington DC, 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address is http://www.sec.gov. 25 ITEM 1A. RISK FACTORS RISKS RELATED TO CMS ENERGY CMS ENERGY DEPENDS ON DIVIDENDS FROM ITS SUBSIDIARIES TO MEET ITS DEBT SERVICE OBLIGATIONS. Due to its holding company structure, CMS Energy depends on dividends from its subsidiaries to meet its debt obligations. Restrictions contained in Consumers' preferred stock provisions and other legal restrictions, such as certain terms in its articles of incorporation, limit Consumers' ability to pay dividends or acquire its own stock from CMS Energy. As of December 31, 2006, the most restrictive provisions in its financing documents allowed Consumers to pay an aggregate of $300 million in dividends to CMS Energy during any year. At December 31, 2006, Consumers had $215 million of unrestricted retained earnings available to pay common stock dividends. If sufficient dividends are not paid to CMS Energy by its subsidiaries, CMS Energy may not be able to generate the funds necessary to fulfill its cash obligations, thereby adversely affecting its liquidity and financial condition. CMS ENERGY HAS SUBSTANTIAL INDEBTEDNESS THAT COULD LIMIT ITS FINANCIAL FLEXIBILITY AND HENCE ITS ABILITY TO MEET ITS DEBT SERVICE OBLIGATIONS. As of December 31, 2006, CMS Energy had outstanding approximately $2.450 billion aggregate principal amount of indebtedness, including approximately $178 million of subordinated indebtedness relating to its convertible preferred securities but excluding approximately $4.495 billion of indebtedness of its subsidiaries. In May 2005, CMS Energy entered into the Sixth Amended and Restated Credit Agreement in the amount of approximately $300 million. As of December 31, 2006, there were approximately $98 million of letters of credit outstanding under the Sixth Amended and Restated Credit Agreement. CMS Energy and its subsidiaries may incur additional indebtedness in the future. The level of CMS Energy's present and future indebtedness could have several important effects on its future operations, including, among others: - a significant portion of its cash flow from operations will be dedicated to the payment of principal and interest on its indebtedness and will not be available for other purposes; - covenants contained in its existing debt arrangements require it to meet certain financial tests, which may affect its flexibility in planning for, and reacting to, changes in its business; - its ability to obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other purposes may be limited; - it may be at a competitive disadvantage to its competitors that are less leveraged; and - its vulnerability to adverse economic and industry conditions may increase. CMS Energy's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon its future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting its operations, many of which are beyond its control. CMS Energy cannot make assurances that its business will continue to generate sufficient cash flow from operations to service its indebtedness. If it is unable to generate sufficient cash flows from operations, it may be required to sell additional assets or obtain additional financings. CMS Energy cannot assure that additional financing will be available on commercially acceptable terms or at all. CMS ENERGY CANNOT PREDICT THE OUTCOME OF CLAIMS REGARDING ITS PARTICIPATION IN THE DEVELOPMENT OF BAY HARBOR OR OTHER LITIGATION IN WHICH SUBSTANTIAL MONETARY CLAIMS ARE INVOLVED. As part of the development of Bay Harbor by certain subsidiaries of CMS Energy, which went forward under an agreement with the MDEQ, third parties constructed a golf course and a park over several abandoned cement kiln dust (CKD) piles, left over from the former cement plant operation on the Bay Harbor site. Pursuant to the agreement with the MDEQ, a water collection system was constructed to recover seep water from one of the CKD piles and CMS Energy built a treatment plant to treat the seep water. In 2002, CMS Energy sold its interest in Bay 26 Harbor, but retained its obligations under previous environmental indemnifications entered into at the inception of the project. In September 2004, the MDEQ issued a notice of noncompliance after finding high-pH seep water in Lake Michigan adjacent to the property. The MDEQ also found higher than acceptable levels of heavy metals, including mercury, in the seep water. In February 2005, the EPA executed an Administrative Order on Consent (AOC) to address problems at Bay Harbor, upon the consent of CMS Land Company (CMS Land) and CMS Capital, LLC, both subsidiaries of CMS Energy. Pursuant to the AOC, the EPA approved a Removal Action Work Plan in July 2005. Among other things, this plan calls for the installation of collection trenches to intercept high pH CKD leachate flow to the lake. All collection systems contemplated in this work plan have been installed. Shoreline effectiveness monitoring is ongoing, and CMS Land is obligated to address any observed exceedances in pH. This may potentially include the augmentation of the collection system. In May 2006, the EPA approved a pilot carbon dioxide augmentation plan to augment the leachate recovery system by improving pH results in the Pine Court area of the collection system. The augmentation system was installed in June 2006. In February 2006, CMS Land submitted to the EPA a proposed Remedial Investigation and Feasibility Study for the East Park CKD pile. The EPA approved a schedule for near-term activities, which include consolidating certain CKD materials and installing collection trenches in the East Park leachate release area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan and Final Engineering Design for Consolidation. CMS Energy and the MDEQ have initiated negotiations of an AOC and to define a long-term remedy at East Park. The owner of one parcel of land at Bay Harbor has filed a lawsuit in Emmet County Circuit Court against CMS Energy and several of its subsidiaries, as well as Bay Harbor Golf Club Inc., Bay Harbor Company LLC, David C. Johnson, and David V. Johnson, one of the developers at Bay Harbor. Several of these defendants have demanded indemnification from CMS Energy and affiliates for the claims made against them in the lawsuit. After a hearing in March 2006 on motions filed by CMS Energy and other defendants, the judge dismissed various counts of the complaint. CMS Energy will defend vigorously the existing case and any other property damage and personal injury claims or lawsuits. In November 2006, the judge ruled against a motion to dismiss the remaining counts, and the action is scheduled to go to trial in May 2007. CMS Land has entered into various access, purchase and settlement agreements with several of the affected landowners at Bay Harbor. CMS Land has purchased five unimproved lots and two lots with houses. At this time, CMS Land believes it has all necessary access arrangements to complete the remediation work required under the AOC. CMS Energy has recorded a cumulative charge of $93 million for its obligations. An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy's financial condition and liquidity and could negatively impact CMS Energy's financial results. CMS Energy cannot predict the ultimate cost or outcome of this matter. In addition to the litigation and proceedings discussed above, CMS Energy or various of its subsidiaries are parties in other pending litigation in which substantial monetary damages are sought. An adverse outcome in one or more of these cases could, depending on the timing and size of any award and the availability of insurance or reimbursement from third parties, have an adverse effect on CMS Energy's financial condition, liquidity or future results of operations. CMS ENERGY RETAINS CONTINGENT LIABILITIES IN CONNECTION WITH ITS ASSET SALES. The agreements CMS Energy enters into for the sale of assets customarily include provisions whereby it is required to: - retain specified preexisting liabilities such as for taxes, pensions, or environmental conditions; - indemnify the buyers against specified risks, including the inaccuracy of representations and warranties it makes; and - require payments to the buyers depending on the outcome of post-closing adjustments, litigation, audits or other reviews. 27 Many of these contingent liabilities can remain open for extended periods of time after the sales are closed. Depending on the extent to which the buyers may ultimately seek to enforce their rights under these contractual provisions, and the resolution of any disputes CMS Energy may have concerning them, these liabilities could have a material adverse effect on its financial condition, liquidity and future results of operations. See ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- EXECUTIVE OVERVIEW. CMS ENERGY HAS MADE SUBSTANTIAL INTERNATIONAL INVESTMENTS THAT ARE SUBJECT TO POSSIBLE NATIONALIZATION, EXPROPRIATION OR INABILITY TO CONVERT CURRENCY. CMS Energy's investments in selected markets around the world in electric generating facilities, natural gas pipelines and electric distribution systems face a number of risks inherent in acquiring, developing and owning these types of international facilities. Although CMS Energy maintains insurance for various risk exposures, including political risk from possible nationalization, expropriation or inability to convert currency, it is exposed to some risks that include local political and economic factors over which it has no control, such as changes in foreign governmental and regulatory policies (including changes in industrial regulation and control and changes in taxation), changing political conditions and international monetary fluctuations. In some cases an investment may have to be abandoned or disposed of at a loss. These factors could have a significant adverse effect on the financial results of the affected subsidiary and CMS Energy's financial position and results of operations. International investments of the type CMS Energy has made are subject to the risk that the investments may be expropriated or that the required agreements, licenses, permits and other approvals may be changed or terminated in violation of their terms. These kinds of changes could result in a partial or total loss of CMS Energy's investment. The local foreign currency may be devalued, the conversion of the currency may be restricted or prohibited or other actions, such as increases in taxes, royalties or import duties, may be taken which adversely affect the value and the recovery of CMS Energy's investment. CMS ENERGY'S NATURAL GAS PIPELINE AND ELECTRIC GENERATION PROJECT LOCATED IN ARGENTINA AND CHILE MAY BE NEGATIVELY IMPACTED BY ARGENTINE GOVERNMENTAL RESTRICTIONS PLACED ON NATURAL GAS EXPORTS TO CHILE AND THE EFFECTS OF THESE RESTRICTIONS ON THE PROJECT'S CONTRACTS FOR THE SALE OF POWER. In 2004, the Argentine government authorized the restriction of exports of natural gas to Chile, giving priority to domestic demand in Argentina. This restriction had a harmful effect on GasAtacama's earnings since GasAtacama's gas-fired electric generating plant is located in Chile and uses Argentine gas for fuel. Bolivia agreed to export 4 million cubic meters of gas per day to Argentina. With the Bolivian gas supply, Argentina relaxed its export restrictions to GasAtacama. In May 2006, the Bolivian government nationalized the natural gas industry and raised prices under its existing gas export contracts. Gas supply to GasAtacama was restricted as Argentina and Bolivia renegotiated the price for gas. In July 2006, Argentina agreed to increase the price it pays for gas from Bolivia. Argentina also announced that it would recover all of this price increase by a special tax on its gas exports. This increased the risk and cost of GasAtacama's fuel supply. In August 2006, a major gas supplier notified GasAtacama that it would no longer deliver gas to GasAtacama under the Argentine government's current policy. In the third quarter of 2006, CMS Energy performed an impairment analysis and recorded an impairment charge of $239 million ($169 million, net of tax and minority interest) on its Consolidated Statements of Income (Loss). At December 31, 2006, the carrying value of CMS Energy's investment in GasAtacama was $117 million. This remaining value continues to be exposed to the threat of a complete gas restriction by Argentina and the inability of GasAtacama to pass through the increased costs associated with such a restriction to its regulated customers. Therefore, if conditions do not improve, the result could be a further impairment of CMS Energy's investment in GasAtacama. In February 2007, CMS Energy announced plans to conduct an auction to sell GasAtacama. CMS Energy expects to complete the sale by the end of 2007. 28 RISKS RELATED TO CMS ENERGY AND CONSUMERS CMS ENERGY AND CONSUMERS HAVE FINANCING NEEDS AND THEY MAY BE UNABLE TO SUCCESSFULLY ACCESS BANK FINANCING OR THE CAPITAL MARKETS. Consumers expects to incur significant costs for capital expenditures, including future environmental regulation compliance, especially compliance with clean air laws. See "CMS Energy and Consumers could incur significant capital expenditures to comply with environmental standards and face difficulty in recovering these costs on a current basis" below. As of December 31, 2006, Consumers had incurred $688 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $147 million of capital expenditures will be made in 2007 through 2011. CMS Energy and Consumers may be subject to liquidity demands pursuant to commercial commitments under guarantees, indemnities and letters of credit. Management is actively pursuing plans to sell assets. There can be no assurances that this business plan will be successful and failure to achieve its goals could have a material adverse effect on CMS Energy's and Consumers' liquidity and operations. CMS Energy continues to explore financing opportunities to supplement its financial plan. These potential opportunities include: refinancing its bank credit facilities, entering into leasing arrangements and refinancing and/or issuing new capital markets debt, preferred stock and/or common equity. CMS Energy cannot guarantee the capital market's acceptance of its securities or predict the impact of factors beyond its control, such as actions of rating agencies. If CMS Energy is unable to access bank financing or the capital markets to incur or refinance indebtedness, there could be a material adverse effect upon its liquidity and operations. Similarly, Consumers currently plans to seek funds through the capital markets and commercial lenders. Entering into new financings is subject in part to capital market receptivity to utility industry securities in general and to Consumers' securities issuances in particular. Consumers cannot guarantee the capital market's acceptance of its securities or predict the impact of factors beyond its control, such as actions of rating agencies. If Consumers is unable to access bank financing or the capital markets to incur or refinance indebtedness, there could be a material adverse effect upon its liquidity and operations. Certain of CMS Energy's securities and those of its affiliates, including Consumers, are rated by various credit rating agencies. Any reduction or withdrawal of one or more of its credit ratings could have a material adverse impact on CMS Energy's ability to access capital on acceptable terms and maintain commodity lines of credit and could make its cost of borrowing higher. If it is unable to maintain commodity lines of credit, CMS Energy may have to post collateral or make prepayments to certain of its suppliers pursuant to existing contracts with them. Further, any adverse developments to Consumers, which provides dividends to CMS Energy, that result in a lowering of Consumers' credit ratings could have an adverse effect on CMS Energy's credit ratings. CMS Energy and Consumers cannot guarantee that any of their current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. PERIODIC REVIEWS OF THE VALUES OF CMS ENERGY'S AND CONSUMERS' ASSETS COULD RESULT IN ACCOUNTING CHARGES. CMS Energy and Consumers are required by GAAP to periodically review the carrying value of their assets, including those that may be sold. Market conditions, the operational characteristics of their assets and other factors could result in recording additional impairment charges for their assets, which could have an adverse effect on their stockholders' equity and their access to additional financing. In addition, they may be required to record impairment charges and/or foreign currency translation losses at the time they sell assets, depending on the sale prices they are able to secure and other factors. CMS ENERGY AND CONSUMERS MAY BE ADVERSELY AFFECTED BY REGULATORY INVESTIGATIONS REGARDING "ROUND-TRIP" TRADING BY CMS MST AS WELL AS CIVIL LAWSUITS REGARDING PRICING INFORMATION THAT CMS MST AND CMS FIELD SERVICES PROVIDED TO MARKET PUBLICATIONS. As a result of round-trip trading transactions (simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price) at CMS MST, CMS Energy is under 29 investigation by the DOJ. CMS Energy received subpoenas in 2002 and 2003 from U.S. Attorneys' Offices regarding investigations of those trades. CMS Energy responded to those subpoenas in 2003 and 2004. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy relating to round-trip trading. The order did not assess a fine and CMS Energy neither admitted nor denied the order's findings. CMS Energy has notified appropriate regulatory and governmental agencies that some employees at CMS MST and CMS Field Services appeared to have provided inaccurate information regarding natural gas trades to various energy industry publications which compile and report index prices. CMS Energy is cooperating with an ongoing investigation by the DOJ regarding this matter. CMS Energy is unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation will have on CMS Energy. The CFTC filed a civil injunctive action against two former CMS Field Services employees in Oklahoma federal district court on February 1, 2005. The action alleges the two engaged in reporting false natural gas trade information, and seeks to enjoin such acts, compel compliance with the Commodities Exchange Act, and impose monetary penalties. A trial has been set for April 2007. CMS Energy is currently advancing legal defense costs to the two individuals in accordance with existing indemnification policies. CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a result of claimed inaccurate natural gas price reporting. Allegations include manipulation of NYMEX natural gas futures and options prices, price-fixing conspiracies, and artificial inflation of natural gas retail prices in California, Colorado, Kansas, Missouri, Tennessee, and Wyoming. In September 2006, CMS MST reached an agreement in principle to settle the master class action suit in California for $7 million. The settlement agreement has been signed. The settlement payment is not due until the court has approved the settlement. CMS Energy deemed this settlement to be probable and accrued the payment in its consolidated financial statements at September 30, 2006. CMS Energy and the other CMS Energy defendants will defend themselves vigorously against all of these matters but cannot predict their outcome. CMS Energy and Consumers cannot predict the outcome of the DOJ investigations and the lawsuits. It is possible that the outcome in one or more of the investigations or the lawsuits could adversely affect CMS Energy's and Consumers' financial condition, liquidity or results of operations. REGULATORY CHANGES AND OTHER DEVELOPMENTS HAVE RESULTED AND COULD CONTINUE TO RESULT IN INCREASED COMPETITION IN THE DOMESTIC ENERGY BUSINESS. GENERALLY, INCREASED COMPETITION THREATENS MARKET SHARE IN CERTAIN SEGMENTS OF CMS ENERGY'S BUSINESS AND CAN REDUCE ITS AND CONSUMERS' PROFITABILITY. Pursuant to the Customer Choice Act, as of January 1, 2002, all electric customers in Michigan have the choice of buying electric generation service from Consumers or an alternative electric supplier. Consumers had experienced, and could experience in the future, a significant increase in competition for generation services due to ROA. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This amount represents 3 percent of Consumers' total distribution load. It is difficult to predict the total amount of electric supply load that may be lost to competitor suppliers in the future. ELECTRIC INDUSTRY REGULATION COULD ADVERSELY AFFECT CMS ENERGY'S AND CONSUMERS' BUSINESS, INCLUDING THEIR ABILITY TO RECOVER COSTS FROM THEIR CUSTOMERS. Federal and state regulation of electric utilities has changed dramatically in the last two decades and could continue to change over the next several years. These changes could adversely affect CMS Energy's and Consumers' business, financial condition and profitability. There are multiple proceedings pending before the FERC involving transmission rates, regional transmission organizations and electric bulk power markets and transmission. FERC is also reviewing the standards under which electric utilities are allowed to participate in wholesale power markets without price restrictions. CMS Energy and Consumers cannot predict the impact of these electric industry restructuring proceedings on their financial position, liquidity or results of operations. 30 CMS ENERGY AND CONSUMERS COULD INCUR SIGNIFICANT CAPITAL EXPENDITURES TO COMPLY WITH ENVIRONMENTAL STANDARDS AND FACE DIFFICULTY IN RECOVERING THESE COSTS ON A CURRENT BASIS. CMS Energy, Consumers, and their subsidiaries are subject to costly and increasingly stringent environmental regulations. They expect that the cost of future environmental compliance, especially compliance with clean air and water laws, will be significant. In 1998, the EPA issued regulations requiring the State of Michigan to further limit nitrogen oxide emissions at coal-fired electric generating plants. The EPA and State of Michigan regulations require Consumers to make significant capital expenditures estimated to be $835 million. As of December 2006, Consumers has incurred $688 million in capital expenditures to comply with these regulations and anticipates that the remaining $147 million of capital expenditures will be made in 2007 through 2011. In addition to modifying coal- fired electric plants, Consumers' compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $3 million per year, which Consumers expects to recover from customers through the PSCR process. In 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. Consumers plans to meet this rule by year-round operation of its selective catalytic reduction control technology units and installation of flue gas desulfurization scrubbers at an estimated total cost of $955 million, to be incurred by 2014. Also in March 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010 and further reductions by 2018. Based on current technology, Consumers anticipates that its capital costs for mercury emissions reductions required by Phase I of the Clean Air Mercury Rule to be less than $50 million and expect these reductions to be implemented by 2010. Phase II requirements of the Clean Air Mercury Rule are not yet known and a cost estimate has not been determined. In April 2006, Michigan's governor announced a plan that would result in mercury emissions reductions of 90 percent by 2015. Consumers is working with the MDEQ on the details of these rules. We will develop a cost estimate when the details of these rules are determined. Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, including potentially carbon dioxide. CMS Energy and Consumers cannot predict whether any of these proposals will be enacted, or the specific requirements of any of these proposals and their effect on future operations and financial results. In addition, the U.S. Supreme Court has agreed to hear a case claiming that the EPA is required by the Clean Air Act to consider regulating carbon dioxide emissions from automobiles. The EPA asserts that it lacks authority to regulate carbon dioxide emissions. If the Supreme Court finds that the EPA has the authority to regulate carbon dioxide emissions in this case, it could result in new federal carbon dioxide regulations for other industries, including the utility industry. To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. CMS Energy and Consumers cannot estimate the potential effect of federal or state level greenhouse gas policy on their future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, CMS Energy and Consumers will continue to monitor greenhouse gas policy developments and assess and respond to their potential implications on their business operations. In March 2004, the EPA issued rules that govern electric generating plant cooling water intake systems. The rules require significant reduction in fish killed by operating equipment. EPA compliance options in the rule were challenged in court. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The court's ruling is expected to increase significantly the cost of complying with this rule. However, the cost to comply will not be known until the EPA's reconsideration is complete. At this time, the EPA has not established a schedule to address the court decision. CMS Energy expects to collect fully from its customers, through the ratemaking process, these and other required environmental expenditures. However, if these expenditures are not recovered from customers in 31 Consumers' rates, CMS Energy and/or Consumers may be required to seek significant additional financing to fund these expenditures, which could strain their cash resources. CMS ENERGY'S AND CONSUMERS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO RISKS THAT ARE BEYOND THEIR CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE TERRORIST ATTACKS OR RELATED ACTS OF WAR. The cost of repairing damage to CMS Energy's and Consumers' facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of insurance recoveries and reserves established for these repairs, may adversely impact their results of operations, financial condition and cash flows. The occurrence or risk of occurrence of future terrorist activity and the high cost or potential unavailability of insurance to cover this terrorist activity may impact their results of operations and financial condition in unpredictable ways. These actions could also result in disruptions of power and fuel markets. In addition, their natural gas distribution system and pipelines could be directly or indirectly harmed by future terrorist activity. CONSUMERS' OWNERSHIP OF A NUCLEAR GENERATING FACILITY CREATES RISK RELATING TO NUCLEAR ENERGY. Consumers owns the Palisades nuclear power plant and is, therefore, subject to the risks of nuclear generation, including the risks associated with the operation of plant facilities and the storage and disposal of spent fuel and other radioactive waste. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, if a serious nuclear incident were to occur at Consumers' plant, it could harm Consumers' results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. In July 2006, Consumers reached an agreement to sell the Palisades nuclear plant to Entergy for $380 million. Consumers also signed a 15-year power purchase agreement for 100 percent of the plant's current electric output. Consumers expects to close the sale in 2007. The sale will result in an immediate reduction in nuclear operating and decommissioning risk. CONSUMERS CURRENTLY UNDERRECOVERS IN ITS RATES ITS PAYMENTS TO THE MCV PARTNERSHIP FOR CAPACITY AND ENERGY. The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990. The cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. We expensed underrecoveries of $57 million in 2006 and we estimate cash underrecoveries of $39 million in 2007. However, we use the direct savings from the RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The MCV Partnership has notified us that it takes issue with our intended exercise of the regulatory out provision. We believe that the provision is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out provision, the MCV Partnership has the right to terminate the MCV PPA, which could affect our reserve margin. We anticipate that the MPSC will review our exercise of the regulatory out provision and the likely consequences of such action in 2007. It is possible that in the event that the MCV Partnership ceases performance under the MCV PPA, prior orders could limit our recovery of replacement power costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the cost of replacement power, this could result in our costs exceeding the recovery amount allowed by the MPSC. We cannot predict the outcome of any future disputes concerning these issues. In January 2005, we implemented the MPSC-approved RCP with modifications. The underlying RCP agreement between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In January 2007, the Michigan 32 Attorney General filed an appeal with the Michigan Supreme Court regarding the MPSC's order approving the RCP. We cannot predict the outcome of these matters. At this time CMS Energy and Consumers cannot predict the impact of these issues on their future earnings or cash flows. CONSUMERS' ENERGY RISK MANAGEMENT STRATEGIES MAY NOT BE EFFECTIVE IN MANAGING FUEL AND ELECTRICITY PRICING RISKS, WHICH COULD RESULT IN UNANTICIPATED LIABILITIES TO CONSUMERS OR INCREASED VOLATILITY OF ITS EARNINGS. Consumers is exposed to changes in market prices for natural gas, coal, electricity and emission credits. Prices for natural gas, coal, electricity and emission credits may fluctuate substantially over relatively short periods of time and expose Consumers to commodity price risk. A substantial portion of Consumers' operating expenses for its plants consists of the costs of obtaining these commodities. Consumers manages these risks using established policies and procedures, and it may use various contracts to manage these risks, including swaps, options, futures and forward contracts. No assurance can be made that these strategies will be successful in managing Consumers' pricing risk, or that they will not result in net liabilities to Consumers as a result of future volatility in these markets. Natural gas prices in particular have historically been volatile. Consumers routinely enters into contracts to offset its positions, such as hedging exposure to the risks of demand, market effects of weather and changes in commodity prices associated with its gas distribution business. These positions are taken in conjunction with the GCR mechanism, which allows Consumers to recover prudently incurred costs associated with those positions. However, Consumers does not always hedge the entire exposure of its operations from commodity price volatility. Furthermore, the ability to hedge exposure to commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, Consumers may not be able to execute its risk management strategies, which could result in greater open positions than preferred at a given time. To the extent that open positions exist, fluctuating commodity prices can improve or diminish CMS Energy's and Consumers' financial results and financial position. ITEM 1B. UNRESOLVED STAFF COMMENTS Not applicable. ITEM 2. PROPERTIES Descriptions of CMS Energy's and Consumers' properties are found in the following sections of Item 1, all of which are incorporated by reference in this Item 2: - BUSINESS -- GENERAL -- Consumers -- Consumers' Properties -- General; - BUSINESS -- BUSINESS SEGMENTS -- Consumers Electric Utility -- Electric Utility Properties; - BUSINESS -- BUSINESS SEGMENTS -- Consumers Gas Utility -- Gas Utility Properties; - BUSINESS -- BUSINESS SEGMENTS -- Natural Gas Transmission -- Natural Gas Transmission Properties; - BUSINESS -- BUSINESS SEGMENTS -- Independent Power Production -- Independent Power Production Properties; and - BUSINESS -- BUSINESS SEGMENTS -- International Energy Distribution. ITEM 3. LEGAL PROCEEDINGS CMS Energy, Consumers and some of their subsidiaries and affiliates are parties to certain routine lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various taxes, and rates and licensing. For additional information regarding various pending administrative and judicial proceedings involving regulatory, operating and environmental matters, 33 see ITEM 1. BUSINESS -- CMS ENERGY AND CONSUMERS REGULATION, both CMS Energy's and Consumers' ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's and Consumers' ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CMS ENERGY SEC REQUEST On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy voluntarily produce documents and data relating to the SEC's inquiry into payments made to the officials or relatives of officials of the government of Equatorial Guinea. On August 17, 2004, CMS Energy submitted its response, advising the SEC of the information and documentation it had available. On March 8, 2005, CMS Energy received a request from the SEC that CMS Energy voluntarily produce certain of such documents. The SEC subsequently issued a formal order of private investigation on this matter on August 1, 2005. CMS Energy and several other companies, which have conducted business in Equatorial Guinea, received subpoenas from the SEC to provide documents regarding payments made to officials or relatives of officials of the government of Equatorial Guinea. CMS Energy is cooperating and will continue to produce documents responsive to the subpoena. GAS INDEX PRICE REPORTING LITIGATION Texas-Ohio Energy, Inc. filed a putative class action lawsuit in the United States District Court for the Eastern District of California in November 2003 against a number of energy companies engaged in the sale of natural gas in the United States (including CMS Energy). The complaint alleged defendants entered into a price-fixing scheme by engaging in activities to manipulate the price of natural gas in California. The complaint alleged violations of the federal Sherman Act, the California Cartwright Act, and the California Business and Professions Code relating to unlawful, unfair and deceptive business practices. The complaint sought both actual and exemplary damages for alleged overcharges, attorneys' fees and injunctive relief regulating defendants' future conduct relating to pricing and price reporting. In April 2004, a Nevada Multidistrict Litigation (MDL) Panel ordered the transfer of the Texas-Ohio case to a pending MDL matter in the Nevada federal district court that at the time involved seven complaints originally filed in various state courts in California. These complaints make allegations similar to those in the Texas-Ohio case regarding price reporting, although none contain a federal Sherman Act claim. In November 2004, those seven complaints, as well as a number of others that were originally filed in various state courts in California and subsequently transferred to the MDL proceeding, were remanded back to California state court. The Texas-Ohio case remained in Nevada federal district court, and defendants, with CMS Energy joining, filed a motion to dismiss. The court issued an order granting the motion to dismiss on April 8, 2005 and entered a judgment in favor of the defendants on April 11, 2005. Texas-Ohio has appealed the dismissal to the Ninth Circuit Court of Appeals. Three federal putative class actions, Fairhaven Power Company v. Encana Corp. et al., Utility Savings & Refund Services LLP v. Reliant Energy Resources Inc. et al., and Abelman Art Glass v. Encana Corp. et al., all of which make allegations similar to those in the Texas-Ohio case regarding price manipulation and seek similar relief, were originally filed in the United States District Court for the Eastern District of California in September 2004, November 2004 and December 2004, respectively. The Fairhaven and Abelman Art Glass cases also include claims for unjust enrichment and a constructive trust. The three complaints were filed against CMS Energy and many of the other defendants named in the Texas-Ohio case. In addition, the Utility Savings case names CMS MST and Cantera Resources Inc. (Cantera Resources Inc. is the parent of Cantera Natural Gas, LLC. and CMS Energy is required to indemnify Cantera Natural Gas, LLC and Cantera Resources Inc. with respect to these actions.) The Fairhaven, Utility Savings and Abelman Art Glass cases have been transferred to the MDL proceeding, where the Texas-Ohio case was pending. Pursuant to stipulation by the parties and court order, defendants were not required to respond to the Fairhaven, Utility Savings and Abelman Art Glass complaints until the court ruled on defendants' motion to dismiss in the Texas- Ohio case. Plaintiffs subsequently filed a consolidated class action complaint alleging violations of federal and California antitrust laws. Defendants filed a motion to dismiss, arguing that the consolidated complaint should be dismissed for the same reasons as the Texas-Ohio case. The court issued 34 an order granting the motion to dismiss on December 19, 2005 and entered judgment in favor of defendants on December 23, 2005. Plaintiffs have appealed the dismissal to the Ninth Circuit Court of Appeals. Commencing in or about February 2004, 15 state law complaints containing allegations similar to those made in the Texas-Ohio case, but generally limited to the California Cartwright Act and unjust enrichment, were filed in various California state courts against many of the same defendants named in the federal price manipulation cases discussed above. In addition to CMS Energy, CMS MST is named in all of the 15 state law complaints. Cantera Gas Company and Cantera Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in all but one complaint. In February 2005, these 15 separate actions, as well as nine other similar actions that were filed in California state court but do not name CMS Energy or any of its former or current subsidiaries, were ordered coordinated with pending coordinated proceedings in the San Diego Superior Court. The 24 state court complaints involving price reporting were coordinated as Natural Gas Antitrust Cases V. Plaintiffs in Natural Gas Antitrust Cases V were ordered to file a consolidated complaint, but a consolidated complaint was filed only for the two putative class action lawsuits. Pursuant to a ruling dated August 23, 2006, CMS Energy, Cantera Gas Company and Cantera Natural Gas, LLC were dismissed as defendants in the master class action and the thirteen non-class actions, due to lack of personal jurisdiction. CMS MST remains a defendant in all of these actions. In September 2006, CMS MST reached an agreement in principle to settle the master class action for $7 million. The settlement agreement has been signed. The settlement payment is not due until the court has approved the settlement. Samuel D. Leggett, et al v. Duke Energy Corporation, et al, a class action complaint brought on behalf of retail and business purchasers of natural gas in Tennessee, was filed in the Chancery Court of Fayette County, Tennessee in January 2005. The complaint contains claims for violations of the Tennessee Trade Practices Act based upon allegations of false reporting of price information by defendants to publications that compile and publish indices of natural gas prices for various natural gas hubs. The complaint seeks statutory full consideration damages and attorneys fees and injunctive relief regulating defendants' future conduct. The defendants include CMS Energy, CMS MST and CMS Field Services. On August 10, 2005, certain defendants, including CMS MST, filed a motion to dismiss and CMS Energy and CMS Field Services filed a motion to dismiss for lack of personal jurisdiction. Defendants attempted to remove the case to federal court, but it was remanded to state court by a federal judge. On February 2, 2007, the state court granted defendants' motion to dismiss the complaint. J.P. Morgan Trust Company, in its capacity as Trustee of the FLI Liquidating Trust, filed an action in Kansas state court in August 2005 against a number of energy companies, including CMS Energy, CMS MST and CMS Field Services. The complaint alleges various claims under the Kansas Restraint of Trade Act relating to reporting false natural gas trade information to publications that report trade information. Plaintiff is seeking statutory full consideration damages for its purchases of natural gas between January 1, 2000 and December 31, 2001. The case was removed to the United States District Court for the District of Kansas on September 8, 2005 and transferred to the MDL proceeding on October 13, 2005. A motion to remand the case back to Kansas state court was denied on April 21, 2006. The court issued an order granting the motion to dismiss on December 18, 2006, and entered judgment in favor of defendants on January 4, 2007. On November 20, 2005, CMS MST was served with a summons and complaint which named CMS Energy, CMS MST and CMS Field Services as defendants in a putative class action filed in Kansas state court, Learjet, Inc., et al. v. Oneok, Inc., et al. Similar to the other actions that have been filed, the complaint alleges that during the putative class period, January 1, 2000 through October 31, 2002, defendants engaged in a scheme to violate the Kansas Restraint of Trade Act by knowingly reporting false or inaccurate information to the publications, thereby affecting the market price of natural gas. Plaintiffs, who allege they purchased natural gas from defendants and others for their facilities, are seeking statutory full consideration damages consisting of the full consideration paid by plaintiffs for natural gas. On December 7, 2005, the case was removed to the United States District Court for the District of Kansas and later that month a motion was filed to transfer the case to the MDL proceeding. On January 6, 2006, plaintiffs filed a motion to remand the case to Kansas state court. On January 23, 2006, a conditional transfer order transferring the case to the MDL proceeding was issued. On February 7, 2006, plaintiffs filed an opposition to the conditional transfer order. The court issued an order dated August 3, 2006 denying the motion to remand the case to Kansas state court. 35 Breckenridge Brewery of Colorado, LLC and BBD Acquisition Co. v. Oneok, Inc., et al., a class action complaint brought on behalf of retail direct purchasers of natural gas in Colorado, was filed in Colorado state court in May 2006. Defendants, including CMS Energy, CMS Field Services, and CMS MST, are alleged to have violated the Colorado Antitrust Act of 1992 in connection with their natural gas price reporting activities. Plaintiffs are seeking full refund damages. The case was removed to the United States District Court for the District of Colorado on June 12, 2006 and a conditional transfer order transferring the case to the MDL proceeding was entered on June 27, 2006. Plaintiffs are seeking to have the case remanded back to Colorado state court. On October 30, 2006, CMS Energy and CMS MST were each served with a summons and complaint which named CMS Energy, CMS MST and CMS Field Services as defendants in an action filed in Missouri state court, titled Missouri Public Service Commission v. Oneok, Inc. The Missouri Public Service Commission purportedly is acting as an assignee of six local distribution companies, and it alleges that from at least January 2000 through at least October 2002, defendants knowingly reported false natural gas prices to publications that compile and publish indices of natural gas prices, and engaged in wash sales. The complaint contains claims for violation of the Missouri Anti-Trust Law, fraud and unjust enrichment. A class action complaint, Arandell Corp., et al v. XCEL Energy Inc., et al, was filed on or about December 15, 2006 in Wisconsin state court on behalf of Wisconsin commercial entities that purchased natural gas between January 1, 2000 and October 31, 2002. Defendants, including CMS Energy, CMS ERM and Cantera Gas Company, LLC, are alleged to have violated Wisconsin's Anti-Trust statute by conspiring to manipulate natural gas prices. Plaintiffs are seeking full consideration damages, plus exemplary damages in an amount equal to three times the actual damages, and attorneys' fees. CMS Energy and the other CMS defendants will defend themselves vigorously against these matters but cannot predict their outcome. ROUND-TRIP TRADING INVESTIGATIONS During the period of May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These so called round- trip trades had no impact on previously reported consolidated net income, earnings per share or cash flows, but had the effect of increasing operating revenues and operating expenses by equal amounts. CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies. Those two individuals filed a motion to dismiss the SEC action, which was denied. QUICKSILVER RESOURCES, INC. Quicksilver sued CMS MST for breach of contract in connection with a Base Contract for Sale and Purchase of natural gas, pursuant to which Quicksilver agreed to sell, and CMS MST to buy, natural gas. Quicksilver contended that a special provision in the contract requires CMS MST to pay Quicksilver 50 percent of the difference between $2.47/MMBtu and the index price each month. CMS MST disagrees with Quicksilver's interpretation of the special provision and contends that it has paid all monies owed for delivery of gas pursuant to the contract. Quicksilver is seeking damages of approximately $126 million, plus prejudgment interest and attorneys' fees, which in CMS Energy's judgment is unsupported by the facts. The judge granted CMS MST's motion for summary judgment. The court of appeals reversed the summary judgment and remanded the case to the trial court. Trial is set for March 19, 2007. CMS Energy will continue to defend vigorously this lawsuit but cannot predict the outcome. 36 CMS ENERGY AND CONSUMERS SECURITIES CLASS ACTION LAWSUITS Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the United States District Court for the Eastern District of Michigan. The cases were consolidated into a single lawsuit (the "Shareholder Action"), which generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the court conditionally certified a class consisting of "all persons who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17, 2002 and who were damaged thereby." The court excluded purchasers of CMS Energy's 8.75 percent Adjustable Convertible Trust Securities ("ACTS") from the class and, in response, a new class action lawsuit was filed on behalf of ACTS purchasers (the "ACTS Action") against the same defendants named in the Shareholder Action. The settlement described below, if approved, will resolve both the Shareholder and ACTS Actions. On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the "MOU") dated December 28, 2006, subject to court approval, regarding settlement of the two class action lawsuits. The settlement was approved by a special committee of independent directors and by the full board of directors. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. The MOU is expected to lead to a detailed stipulation of settlement that will be presented to the assigned federal judge and the affected class in the first quarter of 2007. Under the terms of the MOU, the litigation will be settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy will make a payment of approximately $123 million plus an amount equivalent to interest on the outstanding unpaid settlement balance beginning on the date of preliminary approval of the court and running until the balance of the settlement funds is paid into a settlement account. Out of the total settlement, CMS Energy's insurers will pay approximately $77 million directly to the settlement account. CMS Energy took an approximately $123 million pre-tax charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS Energy makes no admission of liability under the Shareholder Action and the ACTS Action. ENVIRONMENTAL MATTERS CMS Energy and Consumers, as well as their subsidiaries and affiliates are subject to various federal, state and local laws and regulations relating to the environment. Several of these companies have been named parties to various actions involving environmental issues. Based on their present knowledge and subject to future legal and factual developments, they believe it is unlikely that these actions, individually or in total, will have a material adverse effect on their financial condition or future results of operations. For additional information, see both CMS Energy's and Consumers' ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's and Consumers' ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS CMS ENERGY During the fourth quarter of 2006, CMS Energy did not submit any matters to a vote of security holders. CONSUMERS During the fourth quarter of 2006, Consumers did not submit any matters to a vote of security holders. 37 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES CMS ENERGY Market prices for CMS Energy's Common Stock and related security holder matters are contained in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 17 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED), which is incorporated by reference herein. At February 20, 2007, the number of registered holders of CMS Energy Common Stock totaled 51,043, based upon the number of record holders. In January 2003, CMS Energy suspended the payment of dividends on its common stock. On January 26, 2007, CMS Energy's Board of Directors reinstated a quarterly dividend on CMS Energy Common Stock of $0.05 per share, for the first quarter of 2007. Information regarding securities authorized for issuance under equity compensation plans is included in our definitive proxy statement, which is incorporated by reference herein. CONSUMERS Consumers' common stock is privately held by its parent, CMS Energy, and does not trade in the public market. In February, August and November 2006, Consumers paid $40 million, $31 million and $76 million in cash dividends, respectively, on its common stock. In February, May, August and November 2005, Consumers paid $118 million, $49 million, $40 million and $70 million in cash dividends, respectively, on its common stock. ITEM 6. SELECTED FINANCIAL DATA CMS ENERGY Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S SELECTED FINANCIAL INFORMATION, which is incorporated by reference herein. CONSUMERS Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' SELECTED FINANCIAL INFORMATION, which is incorporated by reference herein. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CMS ENERGY Management's discussion and analysis of financial condition and results of operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS, which is incorporated by reference herein. CONSUMERS Management's discussion and analysis of financial condition and results of operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS, which is incorporated by reference herein. 38 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK CMS ENERGY Quantitative and Qualitative Disclosures About Market Risk is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- CRITICAL ACCOUNTING POLICIES -- ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND MARKET RISK INFORMATION, which is incorporated by reference herein. CONSUMERS Quantitative and Qualitative Disclosures About Market Risk is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- CRITICAL ACCOUNTING POLICIES -- ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION, which is incorporated by reference herein. 39 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Index to Financial Statements: CMS ENERGY CORPORATION Selected Financial Information.................................... CMS - 2 Management's Discussion and Analysis Executive Overview............................................. CMS - 3 Forward-Looking Statements and Information..................... CMS - 4 Results of Operations.......................................... CMS - 6 Critical Accounting Policies................................... CMS - 15 Capital Resources and Liquidity................................ CMS - 24 Outlook........................................................ CMS - 27 Implementation of New Accounting Standards..................... CMS - 35 New Accounting Standards Not Yet Effective..................... CMS - 36 Consolidated Financial Statements Consolidated Statements of Income (Loss)....................... CMS - 38 Consolidated Statements of Cash Flows.......................... CMS - 40 Consolidated Balance Sheets.................................... CMS - 42 Consolidated Statements of Common Stockholders' Equity......... CMS - 44 Notes to Consolidated Financial Statements: 1. Corporate Structure and Accounting Policies................ CMS - 46 2. Asset Sales, Impairment Charges and Discontinued Operations................................................. CMS - 51 3. Contingencies.............................................. CMS - 56 4. Financings and Capitalization.............................. CMS - 69 5. Earnings Per Share......................................... CMS - 73 6. Financial and Derivative Instruments....................... CMS - 74 7. Retirement Benefits........................................ CMS - 80 8. Asset Retirement Obligations............................... CMS - 88 9. Income Taxes............................................... CMS - 90 10. Executive Incentive Compensation........................... CMS - 93 11. Leases..................................................... CMS - 94 12. Property, Plant, and Equipment............................. CMS - 96 13. Equity Method Investments.................................. CMS - 97 14. Jointly Owned Regulated Utility Facilities................. CMS - 100 15. Reportable Segments........................................ CMS - 100 16. Consolidation of Variable Interest Entities................ CMS - 102 17. Quarterly Financial and Common Stock Information (Unaudited)................................................ CMS - 104 Report of Independent Registered Public Accounting Firm........... CMS - 105
40 CONSUMERS ENERGY COMPANY Selected Financial Information.................................... CE - 2 Management's Discussion and Analysis Executive Overview............................................. CE - 3 Forward-Looking Statements and Information..................... CE - 4 Results of Operations.......................................... CE - 5 Critical Accounting Policies................................... CE - 12 Capital Resources and Liquidity................................ CE - 18 Outlook........................................................ CE - 22 Implementation of New Accounting Standards..................... CE - 27 New Accounting Standards Not Yet Effective..................... CE - 28 Consolidated Financial Statements Consolidated Statements of Income (Loss)....................... CE - 29 Consolidated Statements of Cash Flows.......................... CE - 30 Consolidated Balance Sheets.................................... CE - 32 Consolidated Statements of Common Stockholder's Equity......... CE - 34 Notes to Consolidated Financial Statements: 1. Corporate Structure and Accounting Policies................ CE - 36 2. Asset Sales and Impairment Charges......................... CE - 41 3. Contingencies.............................................. CE - 42 4. Financings and Capitalization.............................. CE - 51 5. Financial and Derivative Instruments....................... CE - 53 6. Retirement Benefits........................................ CE - 57 7. Asset Retirement Obligations............................... CE - 65 8. Income Taxes............................................... CE - 67 9. Executive Incentive Compensation........................... CE - 69 10. Leases..................................................... CE - 71 11. Property, Plant, and Equipment............................. CE - 72 12. Jointly Owned Regulated Utility Facilities................. CE - 74 13. Reportable Segments........................................ CE - 74 14. Consolidation of Variable Interest Entities................ CE - 76 15. Quarterly Financial and Common Stock Information (Unaudited)................................................ CE - 76 Report of Independent Registered Public Accounting Firm........... CE - 77
41 (CMS ENERGY LOGO) 2006 Consolidated Financial Statements CMS-1 CMS Energy Corporation SELECTED FINANCIAL INFORMATION
2006 2005 2004 2003 2002 ------- ------- ------- ------- ------- Operating revenue (in millions)......... ($) 6,810 6,288 5,472 5,513 8,673 Earnings from equity method investees (in millions)......................... ($) 89 125 115 164 92 Income (loss) from continuing operations (in millions)......................... ($) (85) (98) 127 (42) (394) Cumulative effect of change in accounting (in millions).............. ($) -- -- (2) (24) 18 Net income (loss) (in millions)......... ($) (79) (84) 121 (43) (650) Net income (loss) available to common stockholders (in millions)............ ($) (90) (94) 110 (44) (650) Average common shares outstanding (in thousands)............................ 219,857 211,819 168,553 150,434 139,047 Net income (loss) from continuing operations per average common share CMS Energy -- Basic................ ($) (0.44) (0.51) 0.68 (0.30) (2.84) -- Diluted.............. ($) (0.44) (0.51) 0.67 (0.30) (2.84) Cumulative effect of change in accounting per average common share CMS Energy -- Basic................ ($) -- -- (0.01) (0.16) 0.13 -- Diluted.............. ($) -- -- (0.01) (0.16) 0.13 Net income (loss) per average common share CMS Energy -- Basic................ ($) (0.41) (0.44) 0.65 (0.30) (4.68) -- Diluted.............. ($) (0.41) (0.44) 0.64 (0.30) (4.68) Cash provided by (used in) operations (in millions)......................... ($) 688 599 353 (250) 614 Capital expenditures, excluding acquisitions and capital lease additions (in millions)............... ($) 670 593 525 535 747 Total assets (in millions)(a)........... ($) 15,371 16,041 15,872 13,838 14,781 Long-term debt, excluding current portion (in millions)(a).............. ($) 6,202 6,800 6,444 6,020 5,357 Long-term debt-related parties, excluding current portion (in millions)(b).......................... ($) 178 178 504 684 -- Non-current portion of capital leases and finance lease obligations (in millions)............................. ($) 42 308 315 58 116 Total preferred stock (in millions)..... ($) 305 305 305 305 44 Total Trust Preferred Securities (in millions)(b).......................... ($) -- -- -- -- 883 Cash dividends declared per common share................................. ($) -- -- -- -- 1.09 Market price of common stock at year- end................................... ($) 16.70 14.51 10.45 8.52 9.44 Book value per common share at year- end................................... ($) 10.03 10.53 10.62 9.84 7.48 Number of employees at year-end (full- time equivalents)..................... 8,640 8,713 8,660 8,411 10,477 ELECTRIC UTILITY STATISTICS Sales (billions of kWh)............... 38 39 38 38 38 Customers (in thousands).............. 1,797 1,789 1,772 1,754 1,734 Average sales rate per kWh............ (c) 8.46 6.73 6.88 6.91 6.88 GAS UTILITY STATISTICS Sales and transportation deliveries (bcf).............................. 309 350 385 380 376 Customers (in thousands)(c)........... 1,714 1,708 1,691 1,671 1,652 Average sales rate per mcf............ ($) 10.44 9.61 8.04 6.72 5.67
-------------- (a) Until their sale in November 2006, we were the primary beneficiary of the MCV Partnership and the FMLP. As a result, we consolidated their assets, liabilities and activities into our consolidated financial statements through the date of sale and for the years ended December 31, 2005 and 2004. These partnerships had third party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004. (b) Effective December 31, 2003, Trust Preferred Securities are classified on our consolidated balance sheet as Long-term debt -- related parties. (c) Excludes off-system transportation customers. CMS-2 CMS Energy Corporation Management's Discussion and Analysis This MD&A is a consolidated report of CMS Energy and Consumers. The terms "we" and "our" as used in this report refer to CMS Energy and its subsidiaries as a consolidated entity, except where it is clear that such term means only CMS Energy. EXECUTIVE OVERVIEW CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international energy businesses including independent power production, electric distribution, and natural gas transmission, storage, and processing. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises. We earn our revenue and generate cash from operations by providing electric and natural gas utility services, electric power generation, and gas distribution, transmission, storage, and processing. Our businesses are affected primarily by: - weather, especially during the normal heating and cooling seasons, - economic conditions, primarily in Michigan, - regulation and regulatory issues that affect our electric and gas utility operations, - energy commodity prices, - interest rates, and - our debt credit rating. During the past several years, our business strategy has involved improving our consolidated balance sheet and maintaining focus on our core strength: utility operations and service. In 2006, we announced utility asset sales intended to reduce risk and strengthen our utility business. In July 2006, we reached an agreement to sell the Palisades nuclear plant to Entergy for $380 million. We also signed a 15-year power purchase agreement with Entergy for 100 percent of the plant's current electric output. We are targeting to close the sale in the second quarter of 2007. When completed, the sale will result in an immediate improvement in our cash flow, a reduction in our nuclear operating and decommissioning risk, and an improvement in our financial flexibility to support other utility investments. We expect to use the proceeds to benefit our customers. We plan to use the cash that we retain from the sale to reduce utility debt. In January 2007, the NRC renewed the Palisades operating license for 20 years extending it to 2031. In November 2006, we sold our interests in the MCV Partnership and the FMLP. The sale resulted in a $57 million positive impact on our 2006 cash flow. We used the proceeds to reduce utility debt. The sale reduced our exposure to volatile natural gas prices. Our primary focus with respect to our non-utility businesses has been to optimize cash flow and further reduce our business risk and leverage through the sale of selected assets. In 2007, we intend to exit the international marketplace and accelerate our financial improvement plan through the sale of a major portion of our non-U.S. Enterprises assets. In January 2007, we signed a binding letter of intent to sell most of our Argentine assets and our northern Michigan non-utility natural gas assets to Lucid Energy, LLC for $180 million. We expect to close the proposed sale, which is subject to negotiation and execution of a definitive purchase and sale agreement, in the first half of 2007. In February 2007, we reached an agreement to sell our ownership interests in businesses in the Middle East, Africa, and India for $900 million to TAQA. We expect to close this sale in the middle of 2007. CMS-3 In February 2007, we signed a memorandum of understanding with Petroleos de Venezuela, S.A. to sell our ownership interest in SENECA and certain associated generating equipment for $106 million. We expect to close on the sale by March 31, 2007. In addition, during 2007, we plan to conduct an auction to sell other generation and distribution assets in South America. We plan to use the proceeds from these sales to retire debt and to invest in our utility business. For additional details on our planned asset sales, see the Enterprise Outlook Section with this MD&A. In January 2007, we took an important step in our business plan by reinstating a dividend on our common stock after a four-year suspension. The quarterly dividend is $0.05 per share for the first quarter of 2007. We also took steps toward resolving a long-outstanding litigation issue. In January 2007, we reached a preliminary agreement to settle two class action lawsuits related to round-trip trading by CMS MST. We believe that eliminating this business uncertainty is in the best interests of our shareholders. In the future, we will focus our strategy on: - continued investment in our utility business, - successful completion of announced asset sales, - reducing parent debt, and - growing earnings while controlling operating costs. We continue to pursue opportunities and options for our Enterprises business that enhance value. In October 2006, we signed agreements with Peabody Energy to co-develop, construct, operate, and indirectly own 15 percent of the Prairie State Energy Campus, a 1,600 MW power plant and coal mine in southern Illinois. This project complements our expertise in power plant construction. As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been hampered by negative developments in Michigan's automotive industry and limited growth in the non-automotive sectors of the state's economy. The return of ROA customer load has offset some of these negative effects. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This is 3 percent of our total distribution load and represents a decrease of 46 percent of ROA load compared to the end of December 2005. FORWARD-LOOKING STATEMENTS AND INFORMATION This Form 10-K and other written and oral statements that we make contain forward-looking statements as defined in Rule 3b-6 under the Securities Exchange Act of 1934, as amended, Rule 175 under the Securities Act of 1933, as amended, and relevant legal decisions. Our intention with the use of such words as "may," "could," "anticipates," "believes," "estimates," "expects," "intends," "plans," and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward- looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict and (or) control: - the price of CMS Energy Common Stock, capital and financial market conditions, and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets, including availability of financing to CMS Energy, Consumers, or any of their affiliates, and the energy industry, - market perception of the energy industry, CMS Energy, Consumers, or any of their affiliates, - credit ratings of CMS Energy, Consumers, or any of their affiliates, - currency fluctuations, transfer restrictions, and exchange controls, CMS-4 - factors affecting utility and diversified energy operations, such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints, - international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments, - adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions, including but not limited to Bay Harbor, - potentially adverse regulatory treatment and (or) regulatory lag concerning a number of significant questions presently before the MPSC including: - recovery of Clean Air Act capital and operating costs and other environmental and safety-related expenditures, - power supply and natural gas supply costs when fuel prices are increasing and (or) fluctuating, - timely recognition in rates of additional equity investments in Consumers, - adequate and timely recovery of additional electric and gas rate- based investments, - adequate and timely recovery of higher MISO energy and transmission costs, - recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers, and - sale of the Palisades plant, - the effects on our ability to purchase capacity to serve our customers and fully recover the cost of these purchases, if Consumers exercises its regulatory out rights and the owners of the MCV Facility exercise their right to terminate the MCV PPA, - federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of the market- based sales authorizations in wholesale power markets without price restrictions, - energy markets, including availability of capacity and the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity and certain related products due to lower or higher demand, shortages, transportation costs problems, or other developments, - our ability to collect accounts receivable from our customers, - the GAAP requirement that we utilize mark-to-market accounting on certain energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods and could add to earnings volatility, - the effect on our electric utility of the direct and indirect impacts of the continued economic downturn experienced by our automotive and automotive parts manufacturing customers, - potential disruption, expropriation or interruption of facilities or operations due to accidents, war, terrorism, or changing political conditions, and the ability to obtain or maintain insurance coverage for such events, - changes in available gas supplies or Argentine government regulations that could further restrict natural gas exports to our GasAtacama electric generating plant and the operating and financial effects of the restrictions, including further impairment of our investment in GasAtacama, - nuclear power plant performance, operation, decommissioning, policies, procedures, incidents, and regulation, including the availability of spent nuclear fuel storage, - technological developments in energy production, delivery, and usage, CMS-5 - achievement of capital expenditure and operating expense goals, - changes in financial or regulatory accounting principles or policies, - changes in domestic or foreign tax laws, or new IRS or foreign governmental interpretations of existing or past tax laws, - outcome, cost, and other effects of legal and administrative proceedings, settlements, investigations and claims, including particularly claims, damages, and fines resulting from round-trip trading and inaccurate commodity price reporting, including the outcome of investigations by the DOJ regarding round-trip trading and price reporting, - limitations on our ability to control the development or operation of projects in which our subsidiaries have a minority interest, - disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance and performance bonds, - the ability to efficiently sell assets when deemed appropriate or necessary, including the sale of non-strategic or under-performing domestic or international assets and discontinuation of certain operations, - other business or investment considerations that may be disclosed from time to time in CMS Energy's or Consumers' SEC filings, or in other publicly issued written documents, - the successful close of the sale of our ownership interests in businesses in the Middle East, Africa, and India, - the successful entry into a definitive purchase and sale agreement and closing of the proposed sale of certain of our Argentine assets and our northern Michigan non-utility natural gas assets, - the successful entry into a definitive purchase and sale agreement and closing of the proposed sale of SENECA, - the outcome of the planned auction of other generation and distribution assets in South America, and - other uncertainties that are difficult to predict, many of which are beyond our control. For additional information regarding these and other uncertainties, see the "Outlook" section included in this MD&A, Note 3, Contingencies, and Part I, Item 1A. Risk Factors. RESULTS OF OPERATIONS CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS (EXCEPT FOR PER SHARE AMOUNTS) Net Income (Loss) Available to Common Stockholders......... $ (90) $ (94) $ 110 Basic Earnings (Loss) Per Share............................ $(0.41) $(0.44) $0.65 Diluted Earnings (Loss) Per Share.......................... $(0.41) $(0.44) $0.64
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Electric Utility.......................... $ 199 $ 153 $ 46 $ 153 $ 223 $ (70) Gas Utility............................... 37 48 (11) 48 71 (23) Enterprises............................... (158) (142) (16) (142) 19 (161) Corporate Interest and Other.............. (174) (167) (7) (167) (197) 30 Discontinued Operations................... 6 14 (8) 14 (4) 18 Accounting Changes........................ -- -- -- -- (2) 2 ----- ----- ---- ----- ----- ----- Net Income (Loss) Available to Common Stockholders............................ $ (90) $ (94) $ 4 $ (94) $ 110 $(204) ===== ===== ==== ===== ===== =====
CMS-6 For 2006, our net loss was $90 million compared to a net loss of $94 million for 2005. The improvement is primarily due to increased net income at our electric utility, as the positive effects of recent regulatory actions, the return of open access customers and favorable tax adjustments more than offset the negative impacts of increased operating expenses and milder summer weather. The improvements at the electric utility were essentially negated by earnings reductions or increased losses at our other segments. At our Enterprises segment, the negative impacts of mark-to-market valuation losses and the net loss on the sale of our investment in the MCV Partnership more than offset the reduction in asset impairment charges. At our gas utility, net income decreased as the benefits derived from lower operating costs and a gas rate increase authorized by the MPSC in November 2006 were more than offset by lower, weather- driven sales. At our Corporate Interest and Other segment, the negative earnings impact of our agreement to settle the shareholder class action lawsuits more than offset reduced corporate expenditures. Specific changes to net income (loss) available to common stockholders for 2006 versus 2005 are:
IN MILLIONS ----------- - decrease in asset impairment charges as the $385 million $ 216 impairment related to the MCV Partnership recorded in 2005 exceeded the $169 million impairment related to GasAtacama recorded in 2006, - increase from Enterprises primarily due to favorable 47 arbitration and property tax awards and lower depreciation expense, - increase in earnings from our electric utility primarily due 46 to an increase in revenue from an electric rate order, the return to full service-rates of customers previously using alternative energy suppliers, and the expiration of rate caps in December 2005 offset partially by higher operating expense and lower deliveries due to milder weather, - decrease in corporate interest and other expenses primarily 33 due to an insurance reimbursement received for previously incurred legal expenses, and a reduction in debt retirement charges and other expenses, - lower estimate of environmental remediation expenses 20 recorded in 2006 related to our involvement in Bay Harbor, - decrease in earnings from mark-to-market valuation (203) adjustments primarily at the MCV Partnership and CMS ERM as losses recorded in 2006 replaced gains recorded in 2005, - net charge resulting from our agreement to settle (80) shareholder class action lawsuits, - net loss on the sale of our investment in the MCV (41) Partnership including the negative impact of the associated impairment charge recorded in 2006 and the positive impact of the recognition of certain derivative instruments, - decrease in various corporate and Enterprises tax benefits (15) as the absence of tax benefits recorded in 2005 related to the American Jobs Creation Act more than offset benefits recorded in 2006, primarily related to the restoration and utilization of income tax credits due to the resolution of an IRS income tax audit, - decrease in earnings from our gas utility primarily due to a (11) reduction in deliveries resulting from increased customer conservation efforts and warmer weather in 2006 partially offset by other gas revenue associated with pipeline capacity optimization and a reduction in operation and maintenance expenses, and - reduced earnings from discontinued operations as the (8) positive impact of an arbitration award and a reduction of contingent liabilities recorded in 2005 exceeded income recorded in 2006 from the favorable resolution of certain accrued liabilities. ----- Total Change $ 4 =====
For 2005, our net loss was $94 million compared to net income of $110 million for 2004. The year-over-year change was partially due to a decrease in income from our utilities, which experienced underrecoveries of electric power supply costs and increases in operating and maintenance expenses. Also contributing to the change was a loss at our Enterprises segment due to an increase in asset impairment charges, which more than offset mark-to-market CMS-7 gains on long-term gas contracts and associated hedges at the MCV Partnership. These decreases more than offset the continued reduction in corporate interest expense and lower income tax expenses. Specific changes to net income (loss) available to common stockholders for 2005 versus 2004 are:
IN MILLIONS ----------- - decrease in earnings from our ownership interest in the MCV Partnership due to a $385 million impairment charge to property, plant, and equipment offset partially by an increase of $100 million from operations, primarily due to an increase in fair value of certain long-term gas contracts and financial hedges, $(285) - decrease in earnings at our electric utility primarily due to increased operating and maintenance expenses, an underrecovery of power supply costs, and a reduction in income from the regulatory return on capital expenditures, offset partially by a weather-driven increase in sales to our residential customers and a reduction in interest charges, (70) - lower gains on the sale of assets in 2005, (30) - decrease in earnings at our gas utility primarily due to increased operating and maintenance expenses, offset partially by a MPSC-authorized gas rate surcharge, (23) - increase in other corporate expenses primarily due to legal fees and the expiration of general business tax credits in 2005, (16) - absence in 2005 of impairment charges recorded in 2004 related to the sales of our investments in Loy Yang and GVK, 104 - reduction in corporate interest expense due to lower debt levels and a reduction in average interest rates, 29 - increase in tax benefits from the American Jobs Creation Act of 2004, 24 - increase in income from discontinued operations due to favorable litigation results and the absence of other expenses recorded in 2004, 18 - increase in corporate tax benefits, 17 - increase in Shuweihat earnings, 10 - increase in earnings from other Enterprises' subsidiaries, and 10 - decrease in debt retirement charges. 8 ----- Total Change $(204) =====
ELECTRIC UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Net income.................................. $199 $153 $ 46 $153 $223 $ (70) ==== ==== ===== ==== ==== ===== REASONS FOR THE CHANGE: Electric deliveries......................... $ 254 $ 91 Power supply costs and related revenue...... 57 (46) Other operating expenses, other income, and non-commodity revenue..................... (236) (131) Regulatory return on capital expenditures... 22 (30) General taxes............................... (7) 6 Interest charges............................ (34) 5 Income taxes................................ (10) 35 ----- ----- Total change................................ $ 46 $ (70) ===== =====
ELECTRIC DELIVERIES: In 2006, electric delivery revenues increased by $254 million over 2005 despite the fact that electric deliveries to end-use customers were 38.5 billion kWh, a decrease of 0.4 billion kWh or 1.2 percent versus 2005. The decrease in electric deliveries is primarily due to milder summer weather compared to 2005, and resulted in a decrease in electric delivery revenue of $16 million. Despite lower electric deliveries, electric delivery CMS-8 revenue increased primarily due to an electric rate order, increased surcharge revenue, and the return of former ROA customers to full-service rates. The impact of these three issues on electric delivery revenue are discussed in the following paragraphs. Electric Rate Order: In December 2005, the MPSC issued an order in our electric rate case. The order increased electric tariff rates and impacted PSCR revenue. As a result of this order, electric delivery revenues increased $160 million in 2006 versus 2005. Surcharge Revenue: On January 1, 2006, we started collecting a surcharge that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This surcharge increased electric delivery revenue by $51 million in 2006 versus 2005. In addition, on January 1, 2006, we started collecting customer choice transition costs from our residential customers that increased electric delivery revenue by $12 million in 2006 versus 2005. Other surcharges decreased electric delivery revenue by $2 million in 2006 versus 2005. ROA Customer Deliveries: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This amount represents a decrease of 46 percent of ROA load compared to the end of December 2005. The return of former ROA customers to full-service rates increased electric revenues $49 million in 2006 versus 2005. For 2005, electric deliveries to end-use customers were 38.9 billion kWh, an increase of 1.3 billion kWh or 3.4 percent versus 2004. The corresponding $68 million increase in electric delivery revenue was primarily due to increased sales to residential customers, reflecting warmer summer weather and increased surcharge revenue from all customers. On July 1, 2004, we started collecting a surcharge to recover costs incurred in the transition to customer choice. This surcharge increased electric delivery revenue by $13 million in 2005 versus 2004. Surcharge revenue related to the recovery of Security Costs and Stranded Costs increased electric delivery revenue by an additional $10 million in 2005 versus 2004. POWER SUPPLY COSTS AND RELATED REVENUE: Rate caps for our residential customers expired on December 31, 2005. In 2006, the absence of rate caps allowed us to record power supply revenue to offset fully our power supply costs. Our ability to recover these power supply costs resulted in an $82 million increase in electric revenue in 2006 versus 2005. Additionally, electric revenue increased $9 million in 2006 versus 2005 primarily due to the return of former special-contract customers to full-service rates in 2006. The return of former special-contract customers to full-service rates allowed us to record power supply revenue to offset fully our power supply costs. Partially offsetting these increases was the absence, in 2006, of deferrals of transmission and nitrogen oxide allowance expenditures related to our capped customers recorded in 2005. These costs were not fully recoverable due to the application of rate caps, so we deferred them for recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the MPSC approved the recovery of these costs. For 2005, deferrals of these costs were $34 million. In 2005, our recovery of power supply costs was capped for our residential customers. The underrecovery of power costs related to these capped customers increased by $76 million versus 2004. Partially offsetting these underrecoveries were benefits from the deferral of transmission and nitrogen oxide allowance expenditures related to our capped customers. To the extent these costs were not fully recoverable due to the application of rate caps, we deferred them for recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the MPSC approved the recovery of these costs. For 2005, deferrals of these costs increased by $30 million versus 2004. OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For 2006, other operating expenses increased $236 million. The increase in other operating expenses reflects higher operating and maintenance, customer service, depreciation and amortization, and pension and benefit expenses. Operating and maintenance expense increased primarily due to costs related to a planned refueling outage at our Palisades nuclear plant, and higher tree trimming and storm restoration costs. Higher customer service expense reflects contributions, beginning in January 2006 pursuant to a December 2005 MPSC order, to a fund that provides energy assistance to low-income customers. Depreciation and amortization expense increased due to higher plant in CMS-9 service and greater amortization of certain regulatory assets. The increase in pension and benefit expense reflects changes in actuarial assumptions in 2005, and the latest collective bargaining agreement between the Utility Workers Union of America and Consumers. For 2005, other operating expenses increased $139 million, other income increased $4 million, and non-commodity revenue increased $4 million versus 2004. The increase in other operating expenses reflects higher depreciation and amortization, higher pension and benefit expense, and higher underrecovery expense related to the MCV PPA, offset partially by our direct savings from the RCP. Depreciation and amortization expense increased primarily due to a reduction in 2004 expense to reflect an MPSC order allowing recovery of $57 million of Stranded Costs. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005. In 1992, a liability was established for estimated future underrecoveries of power supply costs under the MCV PPA. In 2004, a portion of the cash underrecoveries continued to reduce this liability until its depletion in December. In 2005, all cash underrecoveries were expensed directly to income. Consequently, the cost associated with the MCV PPA cash underrecoveries increased operating expense $30 million for 2005 versus 2004. Offsetting this increased operating expense were the savings from the RCP approved by the MPSC in January 2005. The RCP allows us to dispatch the MCV Facility on the basis of natural gas prices, which reduces the MCV Facility's annual production of electricity and, as a result, reduces the MCV Facility's consumption of natural gas. The MCV Facility's fuel cost savings are first used to offset the cost of replacement power and fund a renewable energy program. Remaining savings are split between us and the MCV Partnership. Our direct savings were shared 50 percent with customers in 2005 and are being shared 70 percent with customers in 2006 and each year thereafter. Our direct savings, after allocating a portion to customers, was $9 million for 2006 and $32 million for 2005. For 2005, the increase in other income was primarily due to higher interest income on short-term cash investments versus 2004, offset partially by expenses associated with the early retirement of debt. The increase in non-commodity revenue was primarily due to higher transmission services revenue versus 2004. REGULATORY RETURN ON CAPITAL EXPENDITURES: For 2006, the return on capital expenditures in excess of our depreciation base increased income by $22 million versus 2005. The increase reflects the equity return on the regulatory asset authorized by the MPSC's December 2005 order which provided for the recovery of $333 million of Section 10d(4) costs over five years. For 2005, the return on capital expenditures in excess of our depreciation base decreased income by $30 million versus 2004. The decrease reflects a reduction, in 2005, of the equity return on the regulatory asset authorized by the MPSC's December 2005 order. Prior to the MPSC order, the equity return was calculated using a regulatory asset balance that was greater than the amount authorized by the MPSC. GENERAL TAXES: For 2006, the increase in general taxes reflects higher MSBT expense, offset partially by lower property tax expense. For 2005, general taxes decreased primarily due to lower property tax expense, reflecting the use of revised tax tables by several of our taxing authorities and, separately, other property tax refunds. INTEREST CHARGES: For 2006, interest charges increased primarily due to lower capitalized interest and an IRS income tax audit settlement. In 2005, we capitalized $33 million of interest in connection with the MPSC's December 2005 order in our Section 10d(4) Regulatory Asset case. The IRS income tax settlement in 2006 recognized that our taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years. For 2005, interest charges decreased primarily due to higher capitalized interest. In 2005, we capitalized $33 million of interest in connection with the MPSC's December 2005 order in our Section 10d(4) Regulatory Asset case. This benefit was offset partially by higher average debt levels versus 2004. CMS-10 INCOME TAXES: For 2006, income taxes increased versus 2005 primarily due to higher earnings by the electric utility, offset partially by the resolution of an IRS income tax audit, which resulted in a $4 million income tax benefit caused by the restoration and utilization of income tax credits. For 2005, income taxes decreased primarily due to lower earnings versus 2004, offset partially by a $2 million increase to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders. GAS UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Net income.................................... $37 $48 $(11) $48 $71 $(23) === === ==== === === ==== Reasons for the change: Gas deliveries................................ $(61) $ (6) Gas rate increase............................. 14 28 Gas wholesale and retail services, other gas revenues, and other income.................. 24 9 Operation and maintenance..................... 7 (49) General taxes and depreciation................ (10) (4) Interest charges.............................. (6) (2) Income taxes.................................. 21 1 ---- ---- Total change.................................. $(11) $(23) ==== ====
GAS DELIVERIES: In 2006, gas delivery revenues decreased by $61 million versus 2005 as gas deliveries, including miscellaneous transportation to end-use customers, were 282 bcf, a decrease of 36 bcf or 11.3 percent. The decrease in gas deliveries was primarily due to warmer weather in 2006 versus 2005 and increased customer conservation efforts in response to higher gas prices. For 2005, gas delivery revenues reflect lower deliveries to our customers versus 2004. Gas deliveries, including miscellaneous transportation to end-use customers, were 318 bcf, a decrease of 2 bcf or 0.7 percent. GAS RATE INCREASE: In May 2006, the MPSC issued an interim gas rate order authorizing an $18 million annual increase to gas tariff rates. In November 2006, the MPSC issued a final order authorizing an annual increase of $81 million. As a result of these orders, gas revenues increased $14 million for 2006 versus 2005. In December 2003, the MPSC issued an interim gas rate order authorizing a $19 million annual increase to gas tariff rates. In October 2004, the MPSC issued a final order authorizing an annual increase of $58 million. As a result of these orders, gas revenues increased $28 million for 2005 versus 2004. GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES, AND OTHER INCOME: For 2006, the increase in gas wholesale and retail services, other gas revenues, and other income primarily reflects higher pipeline revenues and higher pipeline capacity optimization in 2006 versus 2005. For 2005, other gas revenue increased versus 2004 primarily due to higher interest income on short-term cash investments, offset partially by expenses associated with the early retirement of debt. OPERATION AND MAINTENANCE: For 2006, operation and maintenance expenses decreased versus 2005 primarily due to lower operating expenses, offset partially by higher customer service and pension and benefit expenses. Customer service expense increased primarily due to higher uncollectible accounts expense and contributions, beginning in November 2006 pursuant to a November 2006 MPSC order, to a fund that provides energy assistance to low-income customers. The increase in pension and benefit expense reflects changes in actuarial assumptions in 2005 and the latest collective bargaining agreement between the Utility Workers Union of America and Consumers. CMS-11 For 2005, operation and maintenance expenses increased primarily due to increases in benefit costs and additional safety, reliability, and customer service expenses versus 2004. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005. GENERAL TAXES AND DEPRECIATION: For 2006, depreciation expense increased versus 2005 primarily due to higher plant in service. The increase in general taxes reflects higher MSBT expense, offset partially by lower property tax expense. For 2005, depreciation expense increased primarily due to higher plant in service versus 2004. The decrease in general taxes is primarily due to lower property tax expense versus 2004. Lower property tax expense in 2005 reflects an increased use of revised tax tables by several of Consumers' taxing authorities, and separately, other property tax refunds. INTEREST CHARGES: For 2006, interest charges increased primarily due to higher interest expense on our GCR overrecovery balance and an IRS income tax audit settlement. The settlement recognized that Consumers' taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years. For 2005, interest charges reflect higher average debt levels versus 2004, offset partially by a lower average rate of interest on our debt. INCOME TAXES: For 2006, income taxes decreased versus 2005 primarily due to lower earnings by the gas utility. Also contributing to the decrease was the absence, in 2006, of the write-off of general business credits that expired in 2005, and the resolution of an IRS income tax audit, which resulted in a $3 million income tax benefit caused by the restoration and utilization of income tax credits. For 2005, income taxes decreased due to lower earnings versus 2004. This decrease was offset by $5 million to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders, and the write-off of general business credits expected to expire in 2005. ENTERPRISES RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Net income (loss)......................... $(158) $(142) $ (16) $(142) $19 $ (161) ===== ===== ===== ===== === ======= Reasons for the change: Operating revenues........................ $ 104 $ 244 Cost of gas and purchased power........... (228) (192) Fuel costs mark-to-market at the MCV Partnership............................. (404) 219 Earnings from equity method investees..... (37) 11 Gain on sale of assets.................... 71 (42) Operation and maintenance................. (3) (25) General taxes, depreciation, and other income, net............................. 119 36 Asset impairment charges.................. 726 (1,015) Environmental remediation................. 31 5 Fixed charges............................. 19 13 Minority interest......................... (340) 455 Income taxes.............................. (74) 130 ----- ------- Total change.............................. $ (16) $ (161) ===== =======
CMS-12 OPERATING REVENUES: For 2006, operating revenues increased versus 2005 due to the impact of increased production at our Takoradi plant and increased demand at our South American facilities. Also contributing to the increase was a favorable arbitration settlement of a revenue dispute related to CMS Ensenada. These increases were offset partially by lower revenue at CMS ERM due to mark- to-market losses on power and gas contracts, compared to gains on such items in 2005, and lower third-party power sales. For 2005, operating revenues increased versus 2004 primarily due to the impact of increased third-party power and gas sales and mark-to-market gains on gas contracts at CMS ERM. COST OF GAS AND PURCHASED POWER: For 2006, cost of gas and purchased power increased versus 2005. The increase was primarily due to higher fuel costs related to increased production at Takoradi. Also contributing to the increase was an increase in fuel and power purchases in order to meet customer demand, primarily in South America. These increases were offset partially by decreases in the prices and volumes of cost of gas sold by CMS ERM. For 2005, cost of gas and purchased power increased versus 2004. The increase was primarily due to the impact of natural gas prices on the cost of gas sold and the increased cost of purchased power relating to wholesale power sales at CMS ERM. FUEL COSTS MARK-TO-MARKET AT THE MCV PARTNERSHIP: For 2006, the fuel costs mark-to-market adjustments at the MCV Partnership decreased operating earnings versus 2005 due to the impact of declining gas prices on the market value of certain long-term gas contracts and financial hedges. In order to reflect the market value of these contracts and hedges, mark-to-market losses were recorded in 2006 compared to gains recorded on these assets in 2005. In 2005, gains were primarily due to the marking-to-market of certain long-term gas contracts and financial hedges that, as a result of the implementation of the RCP, no longer qualified as normal purchases or cash flow hedges. For 2005, the fuel costs mark-to-market adjustments of certain long-term gas contracts and financial hedges at the MCV Partnership increased operating earnings due to increased gas prices versus reductions in 2004. EARNINGS FROM EQUITY METHOD INVESTEES: For 2006, equity earnings decreased $37 million versus 2005. The decrease was primarily due to the establishment of tax reserves totaling $23 million related to some of our foreign investments, higher tax expense primarily at Jorf Lasfar of $5 million due to lower tax relief and lower earnings at Shuweihat of $1 million due to higher operating and maintenance costs. For 2005, the increase in equity earnings versus 2004 was primarily due to $10 million in earnings from Shuweihat, which achieved commercial operations in the third quarter of 2004, and a $5 million increase in earnings from GasAtacama, as it was able to import more natural gas from Argentina than in 2004. Also contributing to the increase were higher earnings at Neyveli of $6 million, primarily due to the settlement of a revenue dispute, and $4 million of other net increases in earnings. These increases were offset partially by the absence, in 2005, of $8 million in earnings from Goldfields, which we sold in August 2004 and lower earnings at Jorf Lasfar, primarily due to increases in coal-related costs. GAIN ON SALE OF ASSETS: For 2006, gains on asset sales increased versus 2005. In 2006, we had a gain on the sale of our interest in the MCV Partnership totaling $77 million. In 2005, we had gains on the sale of GVK and SLAP totaling $6 million. For 2005, gains on asset sales decreased versus 2004. In 2005, we had gains on the sale of GVK and SLAP totaling $6 million. In 2004, we had gains on the sale of Goldfields, the Bluewater Pipeline and land in Moapa, Nevada totaling $48 million. OPERATION AND MAINTENANCE: For 2006, operation and maintenance expenses increased versus 2005 due to higher salaries and benefits, primarily at South American subsidiaries, increased expenditures related to prospecting initiatives in North America and higher maintenance expenses at Takoradi and CT Mendoza. These increases were partially offset by a favorable arbitration settlement related to DIG. For 2005, operation and maintenance expenses increased versus 2004 primarily due to a loss on the termination of a prepaid gas contract, higher legal fees and the absence of an insurance settlement received in 2004. Also CMS-13 contributing to the increase were higher maintenance costs related to scheduled outages, new development costs and increased costs at South American subsidiaries related to higher electrical production. GENERAL TAXES, DEPRECIATION, AND OTHER INCOME, NET: For 2006, the net of general tax expense, depreciation and other income increased operating income versus 2005. This was primarily due to the recognition of a property tax refund of $88 million at the MCV Partnership, partially offset by related appeal expenses of $16 million. Also contributing to the increase was lower depreciation expense at the MCV Partnership resulting from the 2005 impairment of property, plant and equipment. For 2005, the net of general tax expense, depreciation, and other income increased operating income versus 2004 primarily due to increased interest income, lower depreciation expense at the MCV Partnership due to the 2005 impairment of property, plant, and equipment, lower accretion expense related to prepaid gas contracts, and the resolution of a contingent liability related to Leonard Field. ASSET IMPAIRMENT CHARGES: For 2006, asset impairment charges decreased versus 2005 primarily due to the absence of a 2005 impairment charge of $1.184 billion to property, plant and equipment at the MCV Partnership offset partially by charges of $218 million related to the sale of the MCV Partnership recorded in 2006. Also in 2006, a charge of $239 million was recorded for the impairment of our equity investment in GasAtacama and related notes receivable. For 2005, the increase in asset impairment charges is primarily due to the impairment of property, plant, and equipment at the MCV Partnership, compared to the 2004 reduction in the fair value of Loy Yang and impairments related to the sale of our interests in GVK and SLAP. ENVIRONMENTAL REMEDIATION: For 2006, we recorded an additional estimated environmental remediation expense of $9 million in 2006 versus $40 million in 2005 related to our involvement in Bay Harbor. For 2005, we recorded an additional estimated environmental remediation expense of $40 million related to our involvement in Bay Harbor. In 2004, we recorded our initial estimate of $45 million. FIXED CHARGES: For 2006, fixed charges decreased versus 2005 due to lower interest expenses at the MCV Partnership as a result of lower debt levels and the sale in November, offset partially by higher interest expense from an increase in subsidiary debt. For 2005, fixed charges decreased compared to 2004 primarily due to lower expense at the MCV Partnership as a result of lower debt levels due to principal payments. MINORITY INTEREST: The allocation of profits to minority owners decreases our net income, and the allocation of losses to minority owners increases our net income. For 2006, minority owners shared in a portion of the reduced losses at our subsidiaries versus sharing greater losses of these subsidiaries in 2005. This was primarily due to the share of impairment charges of $95 million in 2006 versus $591 million in 2005 at the MCV Partnership. For 2005, net losses attributed to minority interest owners in our subsidiaries replaced net gains in 2004. The losses relate to the asset impairment charge to property, plant, and equipment at the MCV Partnership, offset partially by mark-to-market gains at the MCV Partnership. INCOME TAXES: For 2006, the increase in income tax expense versus 2005 reflects higher earnings and resolution of an IRS income tax audit, primarily for the restoration and utilization of income tax credits. Also contributing to the increase was the absence of income tax benefits related to the American Jobs Creation Act recorded in 2005. For 2005, the decrease in income tax expense versus 2004 reflects lower earnings and the income tax benefits related to the American Jobs Creation Act recorded in 2005. SALE OF OUR INTEREST IN THE MCV PARTNERSHIP: This resulted in a net after- tax loss of $41 million in 2006. We recorded Asset impairment charges of $218 million offset by Gain on sale of assets of $77 million, Minority interest of $95 million, and Income taxes of $5 million. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. CMS-14 CORPORATE INTEREST AND OTHER NET EXPENSES
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Net loss.................................. $(174) $(167) $(7) $(167) $(197) $30 ===== ===== === ===== ===== ===
For 2006, corporate interest and other net expenses were $174 million, an increase of $7 million compared to 2005. The increase reflects an $80 million after tax net charge in 2006 as a result of our agreement to settle shareholder class action lawsuits. This impact was offset partially by the 2006 resolution of an IRS income tax audit, which resulted in an income tax benefit primarily for the restoration and utilization of income tax credits. Further offsetting the $80 million charge were lower early debt retirement premiums, and the receipt of insurance proceeds for previously incurred legal expenses. For 2005, corporate interest and other net expenses were $167 million, a decrease of $30 million compared to the same period in 2004. The decrease reflects lower interest expense due to lower average debt levels and a reduction in the average rate of interest. Also contributing to the reduction in expenses were lower debt retirement charges and an increase in corporate income tax benefits. The decrease was offset partially by increased legal fees. DISCONTINUED OPERATIONS: Discontinued operations contributed $6 million in net income for 2006, a decrease of $8 million compared to the same period in 2005. Net income for 2006 was primarily comprised of income from the favorable resolution of certain accrued contingent liabilities associated with previously disposed businesses. Net income of $14 million recorded in 2005 primarily reflects an arbitration award related to the 2003 sale of Marysville and a reduction in contingent liabilities due to favorable results from litigation involving previously sold businesses. A $4 million net loss for 2004 was primarily due to income tax adjustments, offset partially by gains on asset sales. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. ACCOUNTING CHANGES: In 2004, we recorded a $2 million loss for the cumulative effect of a change in accounting principle. The loss was the result of a change in the measurement date on our benefit plans. For additional details, see Note 7, Retirement Benefits. CRITICAL ACCOUNTING POLICIES The following accounting policies are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies. USE OF ESTIMATES AND ASSUMPTIONS We use estimates and assumptions in preparing our consolidated financial statements that may affect reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, and contingencies. For example, we estimate the rate of return on plan assets and the cost of future health-care benefits to determine our annual pension and other postretirement benefit costs. Actual results may differ from estimated results due to factors such as changes in the regulatory environment, competition, foreign exchange, regulatory decisions, and lawsuits. CONTINGENCIES: We are involved in various regulatory and legal proceedings that arise in the ordinary course of our business. We record a liability for contingencies based upon our assessment that a loss is probable and the amount of loss can be reasonably estimated. We use the principles in SFAS No. 5 when recording estimated liabilities for contingencies. We consider many factors in making these assessments, including the history and specifics of each matter. The amount of income taxes we pay is subject to ongoing audits by federal, state, and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have provided adequately for any likely outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments expire. As a CMS-15 result, our effective tax rate may fluctuate significantly on a quarterly basis. In July 2006, the FASB issued a new interpretation on the recognition and measurement of uncertain tax positions. For additional details, see the "New Accounting Standards Not Yet Effective" section included in this MD&A. LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. We periodically perform tests of impairment if certain conditions that are other than temporary exist that may indicate the carrying value may not be recoverable. Of our total assets, recorded at $15.371 billion at December 31, 2006, 56 percent represent long-lived assets and equity method investments that are subject to this type of analysis. We base our evaluations of impairment on such indicators as: - the nature of the assets, - projected future economic benefits, - domestic and foreign regulatory and political environments, - state and federal regulatory and political environments, - historical and future cash flow and profitability measurements, and - other external market conditions or factors. We evaluate an asset for impairment if an event occurs or circumstances change in a manner that indicates the recoverability of a long-lived asset should be assessed. We evaluate an asset held in use for impairment by calculating the undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. If the undiscounted future cash flows are less than the carrying amount, we recognize an impairment loss. The impairment loss recognized is the amount by which the carrying amount exceeds the fair value. We estimate the fair market value of the asset utilizing the best information available. This information includes quoted market prices, market prices of similar assets, and discounted future cash flow analyses. We record an asset considered held for sale at the lower of its carrying amount or fair value, less cost to sell. We assess our ability to recover the carrying amounts of our equity method investments using the fair values of these investments. We determine fair value using valuation methodologies, including discounted cash flows and the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. If the fair value is less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded. Our assessments of fair value using these valuation methodologies represent our best estimates at the time of the reviews and are consistent with our internal planning. The estimates we use can change over time, which could have a material impact on our consolidated financial statements. For additional details on asset impairments, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity. For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate they will require that such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. At December 31, 2006, we had $2.316 billion recorded as regulatory assets and $1.954 billion recorded as regulatory liabilities. CMS-16 ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND MARKET RISK INFORMATION FINANCIAL INSTRUMENTS: Debt and equity securities classified as available- for-sale are reported at fair value determined from quoted market prices. Debt and equity securities classified as held-to-maturity are reported at cost. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of AOCL. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary. Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our consolidated earnings or cash flows. DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if certain contracts must be accounted for as derivative instruments. These criteria are complex and significant judgment is often required in applying the criteria to specific contracts. If a contract is a derivative, it is recorded on our consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. For additional details on accounting for derivatives, see Note 6, Financial and Derivative Instruments. To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. Changes in forward prices or volatilities could significantly change the calculated fair value of our derivative contracts. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of our counterparties. The following table summarizes the interest rate and volatility rate assumptions we used to value these contracts at December 31, 2006:
INTEREST RATES (%) VOLATILITY RATES (%) ------------------ -------------------- Gas-related option contracts........................ 5.00 51 - 62 Electricity-related option contracts................ 5.00 44 - 104
The types of contracts we typically classify as derivative instruments are interest rate swaps, gas supply options, certain gas and electric forward contracts, electric and gas options, electric swaps, and foreign currency exchange contracts. The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because: - they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MWh of electricity or bcf of natural gas), - they qualify for the normal purchases and sales exception, or - there is not an active market for the commodity. Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. If an active market for coal develops in the future, some of these contracts may qualify as derivatives and the resulting mark-to-market impact on earnings could be material. Establishment of the Midwest Energy Market: In 2005, the MISO began operating the Midwest Energy Market. As of December 31, 2006, we have determined that, due to the increased liquidity for electricity within the Midwest Energy Market since its inception, it is our best judgment that this market should be considered an active market, as defined by SFAS No. 133. This conclusion does not impact how we account for our electric capacity and energy contracts, however, because these contracts qualify for the normal purchases and sales exception and, as a result, are not required to be marked-to-market. Derivatives Associated with the MCV Partnership: In November 2006, we sold our interest in the MCV Partnership. In conjunction with that sale, our interest in all of the MCV Partnership's long-term gas contracts and CMS-17 related futures, options, and swaps was sold. Before the sale, we accounted for certain long-term gas contracts and all of the related futures, options, and swaps as derivatives. Certain of these derivatives, specifically the long-term gas contracts, the options, and a portion of the futures and swaps, did not qualify for cash flow hedge accounting treatment. As such, we recorded the mark-to-market gains and losses from these derivatives in earnings each quarter. The gains and losses recorded in earnings during 2006, through the date of the sale, were as follows:
2006 --------------------------------------------- FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL ------- ------- ------- ------- ----- IN MILLIONS Long-term gas contracts...................... $(111) $(34) $(16) $10 $(151) Related futures, options, and swaps.......... (45) (8) (12) 12 (53) ----- ---- ---- --- ----- Total........................................ $(156) $(42) $(28) $22 $(204) ===== ==== ==== === =====
These derivatives incurred significant mark-to-market losses in the first three quarters of the year, due to the decrease in natural gas prices during that time. In the fourth quarter (through the date of the sale), natural gas prices increased, resulting in a mark-to-market gain. The overall net losses, shown before consideration of tax effects and minority interest, are included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss). The remaining futures and swaps held by the MCV Partnership did qualify for cash flow hedge accounting. As such, we recorded our proportionate share of the mark-to-market gains and losses from these derivatives in AOCL each quarter. As of the date of the sale, we had accumulated a net gain of $30 million, net of tax and minority interest, in AOCL representing our proportionate share of the mark-to-market gains from these cash flow hedges. After the sale, this amount was reclassified to and recognized in earnings as a reduction of the total loss on the sale in our Consolidated Statements of Income (Loss). As a result of the sale, we no longer consolidate the MCV Partnership. Accordingly, we no longer record the fair value of the long-term gas contracts and related futures, options, and swaps on our Consolidated Balance Sheets and are not required to record gains or losses related to changes in the fair value of these contracts in earnings or AOCL. For additional details on the sale of our interest in the MCV Partnership, see the "Other Electric Utility Business Uncertainties -- The MCV Partnership" section in this MD&A and Note 2, Asset Sales, Impairment Charges and Discontinued Operations. CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts that support CMS Energy's ongoing operations. CMS ERM holds certain contracts for the future purchase and sale of electricity and natural gas that will result in physical delivery of the commodity at contractual prices. These forward contracts are generally long-term in nature and are classified as non-trading. CMS ERM also uses various financial instruments, including swaps, options, and futures, to manage commodity price risks associated with its forward purchase and sale contracts and with generation assets owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading activities. In accordance with SFAS No. 133, non-trading and trading contracts that qualify as derivatives are recorded at fair value on our Consolidated Balance Sheets. The resulting assets and liabilities are marked to market each quarter, and the changes in fair value are recorded in earnings. For trading contracts, these gains and losses are recorded net in accordance with EITF Issue No. 02-03. Contracts that do not meet the definition of a derivative are accounted for as executory contracts (that is, on an accrual basis). CMS-18 We include the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The following tables provide a summary of these contracts at December 31, 2006:
NON- TRADING TRADING TOTAL ------- ------- ----- IN MILLIONS Fair value of contracts outstanding at December 31, 2005................................................... $(63) $ 100 $ 37 Fair value of new contracts when entered into during the period(a).............................................. -- (11) (11) Contracts realized or otherwise settled during the period................................................. 117(b) (116)(c) 1 Other changes in fair value(d)........................... (23) (41) (64) ---- ----- ---- Fair value of contracts outstanding at December 31, 2006................................................... $ 31 $ (68) $(37) ==== ===== ====
-------------- (a) Reflects only the initial premium payments (receipts) for new contracts. No unrealized gains or losses were recognized at the inception of any new contracts. (b) During the third quarter of 2006, CMS ERM terminated certain non-trading gas contracts. CMS ERM had recorded derivative liabilities, representing cumulative unrealized mark-to-market losses, associated with these contracts. As the contracts are now settled, the related derivative liabilities are no longer included in the balance of CMS ERM's non-trading derivative contracts at December 31, 2006 and, as a result, that balance has changed significantly from December 31, 2005 and is now an asset. (c) During the third quarter of 2006, CMS ERM terminated certain trading gas contracts. CMS ERM had recorded derivative assets, representing cumulative unrealized mark-to-market gains, associated with these contracts. As the contracts are now settled, the related derivative assets are no longer included in the balance of CMS ERM's trading derivative contracts at December 31, 2006 and, as a result, that balance has changed significantly from December 31, 2005 and is now a liability. (d) Reflects changes in the fair value of contracts over the period, as well as increases or decreases to credit reserves.
FAIR VALUE OF NON-TRADING CONTRACTS AT DECEMBER 31, 2006 ---------------------------------------------- MATURITY (IN YEARS) TOTAL ---------------------------------------------- SOURCE OF FAIR VALUE FAIR VALUE LESS THAN 1 1 TO 3 4 TO 5 GREATER THAN 5 -------------------- ---------- ----------- ------ ------ -------------- IN MILLIONS Prices actively quoted................... $-- $-- $-- $-- $-- Prices obtained from external sources or based on models and other valuation methods................................ 31 12 19 -- -- --- --- --- --- --- Total.................................... $31 $12 $19 $-- $-- === === === === ===
FAIR VALUE OF TRADING CONTRACTS AT DECEMBER 31, 2006 ---------------------------------------------- MATURITY (IN YEARS) TOTAL ---------------------------------------------- SOURCE OF FAIR VALUE FAIR VALUE LESS THAN 1 1 TO 3 4 TO 5 GREATER THAN 5 -------------------- ---------- ----------- ------ ------ -------------- IN MILLIONS Prices actively quoted................... $(40) $(15) $(25) $-- $-- Prices obtained from external sources or based on models and other valuation methods................................ (28) (22) (6) -- -- ---- ---- ---- --- --- Total.................................... $(68) $(37) $(31) $-- $-- ==== ==== ==== === ===
MARKET RISK INFORMATION: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, currency exchange rates, and equity security prices. We may use various contracts to manage these risks, including swaps, options, futures, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of both: - an executive oversight committee consisting of senior management representatives, and CMS-19 - a risk committee consisting of business unit managers. Our intention is to limit our exposure to risk from interest rate, commodity price, and currency exchange rate volatility. These contracts contain credit risk, which is the risk that counterparties, primarily financial institutions and energy marketers, will fail to perform their contractual obligations. We reduce this risk through established credit policies, which include performing financial credit reviews of our counterparties. We determine our counterparties' credit quality using a number of factors, including credit ratings, disclosed financial condition, and collateral requirements. If terms permit, we use standard agreements that allow us to net positive and negative exposures associated with the same counterparty. Based on these policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance. The following risk sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical adverse change in market rates or prices of 10 percent. Changes in excess of the amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift used for the analyses. Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital. Interest Rate Risk Sensitivity Analysis (assuming an increase in market interest rates of 10 percent):
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Variable-rate financing -- before-tax annual earnings exposure.... $ 4 $ 4 Fixed-rate financing -- potential REDUCTION in fair value(a)...... 193 223
-------------- (a) Fair value reduction could only be realized if we repurchased all of our fixed-rate financing. Certain entities in which we have a minority interest have entered into interest rate swaps. These instruments are not included in the sensitivity analysis above, but can have an impact on financial results. Commodity Price Risk: Operating in the energy industry, we are exposed to commodity price risk, which arises from fluctuations in the price of electricity, natural gas, coal, and other commodities. Commodity prices are influenced by a number of factors, including weather, changes in supply and demand, and liquidity of commodity markets. In order to manage commodity price risk, we enter into various non-trading derivative contracts, such as gas supply call and put options and forward purchase and sale contracts for electricity and natural gas. We also enter into trading derivative contracts, including electric and gas options and swaps. For additional details on these contracts, see Note 6, Financial and Derivative Instruments. CMS-20 Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market prices of 10 percent):
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Potential REDUCTION in fair value: Non-trading contracts Gas supply option contracts...................................... $-- $ 1 Fixed fuel price contracts(a).................................... 1 -- CMS ERM gas forward contracts.................................... 3 -- Derivative contracts associated with the MCV Partnership: Long-term gas contracts(b).................................... -- 39 Gas futures, options, and swaps(b)............................ -- 48 Trading contracts Electricity-related option contracts............................. 3 2 Electricity-related swaps........................................ -- 13 Gas-related option contracts..................................... 1 1 Gas-related swaps and futures.................................... 1 4
-------------- (a) We have entered into two contracts that, from January to September 2007, will fix the prices we pay for gasoline and diesel fuel used in our fleet vehicles and equipment. These contracts are derivatives with an immaterial fair value at December 31, 2006. (b) The potential reduction in fair value for the MCV Partnership's long-term gas contracts and gas futures, options, and swaps decreased to $0 as a result of the sale of our interest in the MCV Partnership. In conjunction with that sale, our interest in these contracts was also sold and, as a result, we no longer record the fair value of these contracts on our Consolidated Balance Sheets at December 31, 2006. Currency Exchange Risk: Our investments in foreign operations and equity interests in various international projects expose us to currency exchange risk. In order to protect the company from the risk associated with unfavorable changes in currency exchange rates, which could materially affect cash flow, we may use risk mitigating instruments. These instruments, such as forward exchange contracts, allow us to hedge currency exchange rates. At December 31, 2006 and 2005, we had no outstanding foreign exchange contracts. In January and February 2007, we reached agreements and announced plans to sell our ownership interests in businesses in the Middle East, Africa, India, and Latin America. The sale of these investments will significantly reduce our exposure to currency exchange risk. Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available- for-sale investments. Investment Securities Price Risk Sensitivity Analysis (assuming an adverse change in market prices of 10 percent):
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Potential REDUCTION in fair value of available-for-sale equity securities (primarily SERP investments):......................... $6 $5
Consumers maintains trust funds, as required by the NRC, for the purpose of funding certain costs of nuclear plant decommissioning. These funds are invested primarily in equity securities, fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are recorded at fair value on our Consolidated Balance Sheets. These investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear plant decommissioning recognizes that costs are recovered through Consumers' electric rates, fluctuations in equity prices or interest rates do not affect our consolidated earnings or cash flows. CMS-21 For additional details on market risk and derivative activities, see Note 6, Financial and Derivative Instruments. For additional details on nuclear plant decommissioning at Big Rock and Palisades, see the "Other Electric Utility Business Uncertainties -- Nuclear Matters" section included in this MD&A. ACCOUNTING FOR PENSION AND OPEB Pension: We have external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. On September 1, 2005, the defined benefit Pension Plan was closed to new participants and we implemented the DCCP, which provides an employer contribution of 5 percent of base pay to the existing Employees' Savings Plan. An employee contribution is not required to receive the plan's employer cash contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Previous cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. 401(k): We resumed the employer's match in CMS Energy Common Stock in our 401(k) Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages. Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be an investment option available for new investments in the 401(k) Savings Plan and the employer's match will no longer be in CMS Energy Common Stock. Participants will have the opportunity to reallocate investments in CMS Energy Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment options. At February 20, 2007, there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy Stock Fund. OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. In accordance with SFAS No. 158, we record liabilities for pension and OPEB on our consolidated balance sheet at the present value of their future obligations, net of any plan assets. We use SFAS No. 87 to account for pension expense and SFAS No. 106 to account for other postretirement benefit expense. The calculation of the liabilities and associated expenses requires the expertise of actuaries, and require many assumptions, including: - life expectancies, - present-value discount rates, - expected long-term rate of return on plan assets, - rate of compensation increases, and - anticipated health care costs. A change in these assumptions could change significantly our recorded liabilities and associated expenses. The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
EXPECTED COSTS PENSION COST OPEB COST CONTRIBUTIONS -------------- ------------ --------- ------------- IN MILLIONS 2007.............................................. $109 $44 $160 2008.............................................. 105 41 51 2009.............................................. 113 39 51
Actual future pension cost and contributions will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Pension Plan. Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.25 percent to 8.00 percent) would increase estimated pension cost for 2007 by $2 million. Lowering the discount rate by 0.25 percent (from 5.65 percent to 5.40 percent) would increase estimated pension cost for 2007 by $1 million. CMS-22 For additional details on postretirement benefits, see Note 7, Retirement Benefits. ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS SFAS No. 143, as clarified by FASB Interpretation No. 47, requires companies to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. For Consumers, as required by SFAS No. 71, we account for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle. The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. In addition, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates. For additional details see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase Agreement," and Note 8, Asset Retirement Obligations. ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS The MPSC and the FERC regulate the recovery of costs to decommission, or remove from service, our Big Rock and Palisades nuclear plants. Our decommissioning cost estimates for the Big Rock and Palisades plants assume: - each plant site will be restored to conform to the adjacent landscape, - all contaminated equipment and material will be removed and disposed of in a licensed burial facility, and - the site will be released for unrestricted use. Independent contractors with expertise in decommissioning assist us in developing decommissioning cost estimates. We use various inflation rates for labor, non-labor, and contaminated equipment disposal costs to escalate these cost estimates to the future decommissioning cost. A portion of future decommissioning cost will result from the failure of the DOE to remove spent nuclear fuel from the sites, as required by the Nuclear Waste Policy Act of 1982. We have external trust funds to finance the decommissioning of both plants. We record the trust fund balances as a non-current asset on our Consolidated Balance Sheets. The decommissioning trust funds include equities and fixed- income investments. Equities are converted to fixed-income investments during decommissioning, and fixed-income investments are converted to cash as needed. The costs of decommissioning these sites and the adequacy of the trust funds could be affected by: - variances from expected trust earnings, - a lower recovery of costs from the DOE and lower rate recovery from customers, and - changes in decommissioning technology, regulations, estimates, or assumptions. Based on current projections, the current level of funds provided by the trusts is not adequate to fund fully the decommissioning of Big Rock. This is due in part to the DOE's failure to accept the spent nuclear fuel on schedule CMS-23 and lower returns on the trust funds. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation. For additional details, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase Agreement," "Nuclear Plant Decommissioning" and "Nuclear Matters," and Note 8, Asset Retirement Obligations. CAPITAL RESOURCES AND LIQUIDITY Factors affecting our liquidity and capital requirements are: - results of operations, - capital expenditures, - energy commodity and transportation costs, - contractual obligations, - regulatory decisions, - debt maturities, - credit ratings, - working capital needs, and - collateral requirements. During the summer months, we purchase natural gas and store it for resale primarily during the winter heating season. Although our prudent natural gas costs are recoverable from our customers, the amount paid for natural gas stored as inventory requires additional liquidity due to the lag in cost recovery. We have credit agreements with our commodity suppliers containing terms that have previously resulted in margin calls. While we currently have no outstanding margin calls associated with our natural gas purchases, they may be required if agency ratings are lowered or if market conditions become unfavorable relative to our obligations to those parties. Our current financial plan includes controlling operating expenses and capital expenditures, executing on asset sales and evaluating market conditions for financing opportunities, if needed. We believe the following items will be sufficient to meet our liquidity needs: - our current level of cash and revolving credit facilities, - our anticipated cash flows from operating and investing activities, including asset sales, and - our ability to access secured and unsecured borrowing capacity in the capital markets, if necessary. In the second quarter of 2006, Moody's affirmed our liquidity rating and revised the credit rating outlook for Consumers to stable from negative. In the third quarter of 2006, Moody's upgraded Consumers' and CMS Energy's credit ratings. In January 2007, the Board of Directors voted to reinstate a quarterly common stock dividend of $0.05 per share, for the first quarter of 2007. The dividend is payable February 28, 2007 to shareholders of record on February 7, 2007. CASH POSITION, INVESTING, AND FINANCING Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2006, $422 million consolidated cash was on hand, which includes $71 million of restricted cash and $5 million from entities consolidated pursuant to FASB Interpretation No. 46(R). For additional details, see Note 16, Consolidation of Variable Interest Entities. Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For the year ended December 31, 2006, Consumers paid $147 million in common stock dividends to CMS Energy. CMS-24 SUMMARY OF CASH FLOWS:
2006 2005 2004 ---- ---- ---- IN MILLIONS Net cash provided by (used in): Operating activities..................................... $ 688 $ 599 $ 353 Investing activities..................................... (751) (494) (347) ----- ----- ----- Net cash provided by (used in) operating and investing activities............................................... (63) 105 6 Financing activities..................................... (434) 74 (43) Effect of exchange rates on cash........................... 1 (1) -- ----- ----- ----- Net Increase (Decrease) in Cash and Cash Equivalents....... $(496) $ 178 $ (37) ===== ===== =====
OPERATING ACTIVITIES: 2006: Net cash provided by operating activities was $688 million, an increase of $89 million versus 2005. This was the result of a decrease in accounts receivable, reduced inventory purchases, cash proceeds from the sale of excess sulfur dioxide allowances, and a return of funds formerly held as collateral under certain gas hedging arrangements. These changes were offset partially by decreases in the MCV Partnership gas supplier funds on deposit. The decrease in accounts receivable was primarily due to the collection of receivables in 2006 reflecting higher gas prices billed during the latter part of 2005 and reduced billings in the latter part of 2006 due to milder weather. The decrease in the MCV Partnership gas supplier funds on deposit was the result of refunds to suppliers from decreased exposure due to declining gas prices in 2006. 2005: Net cash provided by operating activities was $599 million, an increase of $246 million versus 2004. Included in cash provided by operations is an insurance settlement, a decrease in prepaid gas margin call costs, the positive effect of rising gas prices on accounts payable and the MCV Partnership gas supplier funds on deposit, and other timing differences. These increases were offset partially by the negative effect of rising gas prices on accounts receivable and inventories. INVESTING ACTIVITIES: 2006: Net cash used in investing activities was $751 million, an increase of $257 million versus 2005. This was primarily due to cash relinquished from the sale of assets, the absence of short-term investment proceeds, an increase in capital expenditures and cost to retire property, and an increase in non- current notes receivable. This activity was offset by the release of restricted cash in February 2006, which we used to extinguish long-term debt -- related parties. 2005: Net cash used in investing activities was $494 million, an increase of $147 million versus 2004. This was primarily due to an increase in restricted cash and restricted short-term investments combined with a decrease in proceeds from asset sales. These changes were offset partially by a net increase in short-term investment proceeds and a decrease in investments in unconsolidated subsidiaries. The increase in restricted cash and restricted short-term investments was due to a deposit made with a trustee for extinguishing the current portion of long-term debt -- related parties. FINANCING ACTIVITIES: 2006: Net cash used in financing activities was $434 million, an increase of $508 million versus 2005. This was due to an increase in net retirement of long-term debt of $269 million combined with a decrease in proceeds from common stock issuances of $287 million. 2005: Net cash provided by financing activities was $74 million, an increase of $117 million versus 2004. This was primarily due to a decrease in debt retirements of $122 million. For additional details on long-term debt activity, see Note 4, Financings and Capitalization. CMS-25 OBLIGATIONS AND COMMITMENTS CONTRACTUAL OBLIGATIONS: The following table summarizes our contractual cash obligations for each of the periods presented. The table shows the timing and effect that such obligations are expected to have on our liquidity and cash flow in future periods. The table excludes all amounts classified as current liabilities on our Consolidated Balance Sheets, other than the current portion of long-term debt and capital and finance leases.
PAYMENTS DUE ----------------------------------------------------------- CONTRACTUAL OBLIGATIONS AT LESS THAN ONE TO THREE TO MORE THAN DECEMBER 31, 2006 TOTAL ONE YEAR THREE YEARS FIVE YEARS FIVE YEARS -------------------------- ----- --------- ----------- ---------- ---------- IN MILLIONS Long-term debt(a)..................... $ 6,753 $ 401 $1,651 $1,013 $ 3,688 Long-term debt -- related parties(a).. 178 -- -- -- 178 Interest payments on long-term debt(b)............................. 2,972 403 652 473 1,444 Capital leases(c)..................... 55 13 14 10 18 Interest payments on capital leases(d)........................... 26 -- 9 6 11 Operating leases(e)................... 164 25 44 34 61 Purchase obligations(f)............... 16,334 2,118 2,109 1,661 10,446 ------- ------ ------ ------ ------- Total contractual obligations....... $26,482 $2,960 $4,479 $3,197 $15,846 ======= ====== ====== ====== =======
-------------- (a) Principal amounts due on outstanding debt obligations, current and long- term, at December 31, 2006. For additional details on long-term debt, see Note 4, Financings and Capitalization. (b) Currently scheduled interest payments on both variable and fixed rate long-term debt and long-term debt -- related parties, current and long- term. Variable interest payments are based on contractual rates in effect at December 31, 2006. (c) Minimum lease payments under our capital leases, comprised mainly of leased service vehicles, leased office furniture, and certain power purchase agreements. (d) Imputed interest in the capital leases. (e) Minimum noncancelable lease payments under our leases of railroad cars, certain vehicles, and miscellaneous office buildings and equipment, which are accounted for as operating leases. (f) Long-term contracts for purchase of commodities and services. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. These commodities and services include: - natural gas and associated transportation, - electricity, and - coal and associated transportation. Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $42 million per month during 2007. If a plant is not available to deliver electricity, we are not obligated to make these payments to the plant for that period of time. For additional details on power supply costs, see "Electric Utility Results of Operations" within this MD&A and Note 3, Contingencies, "Consumers' Electric Utility Rate Matters -- Power Supply Costs." REVOLVING CREDIT FACILITIES: At December 31, 2006, CMS Energy had $202 million available and Consumers had $742 million available in secured revolving credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. For additional details on revolving credit facilities, see Note 4, Financings and Capitalization. OFF-BALANCE SHEET ARRANGEMENTS: CMS Energy and certain of its subsidiaries enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, letters of credit, surety bonds, and financial and performance guarantees. CMS-26 We enter into agreements containing indemnifications standard in the industry and indemnifications specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually agreements to reimburse other companies if those companies incur losses due to third-party claims or breach of contract terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a third-party. Letters of credit substitute the bank's credit for ours and reduce credit risk for the third-party beneficiary. We monitor these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. In February 2007, we reached an agreement to sell our ownership interests in businesses in the Middle East, Africa, and India to TAQA. The proposed agreement calls for TAQA to either arrange for substitute guarantee agreements to replace our contingent obligations related to our project-financing security agreements or assume all of our contingent obligations under such agreements. For more details on the sale of our ownership interests to TAQA, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. For additional details on these and other guarantee arrangements, see Note 3, Contingencies, "Other Contingencies -- FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Non-recourse Debt: Our share of unconsolidated debt associated with partnerships and joint ventures in which we have a minority interest is non- recourse and totals $1.167 billion at December 31, 2006. The timing of the payments of non-recourse debt only affects the cash flow and liquidity of the partnerships and joint ventures. For summarized financial information of our investments in certain partnerships and joint ventures, see Note 13, Equity Method Investments. Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for securitized financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see Note 4, Financings and Capitalization. DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4, Financings and Capitalization. CAPITAL EXPENDITURES: We estimate that we will make the following capital expenditures, including new lease commitments, during 2007 through 2009. We prepare these estimates for planning purposes. Periodically, we review these estimates and may revise them due to a number of factors including environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.
YEARS ENDING DECEMBER 31 2007 2008 2009 ------------------------ ---- ---- ---- IN MILLIONS Electric utility operations(a)(b)............................ $618 $487 $455 Gas utility operations(b).................................... 164 216 274 Enterprises.................................................. 65 92 124 ---- ---- ---- $847 $795 $853 ==== ==== ====
-------------- (a) These amounts include estimates for capital expenditures that may be required by recent revisions to the Clean Air Act's national air quality standards. (b) These amounts include estimates for capital expenditures related to information technology projects, facility improvements, and vehicle leasing. OUTLOOK CORPORATE OUTLOOK Over the next few years, our primary business strategy will focus on the successful completion of announced asset sales, continued investment in our utility business, reducing parent debt, and growing earnings while controlling operating costs. In November 2006, we announced a reorganization of our utility business to improve operating efficiency, reliability, and customer service. CMS-27 Our primary focus with respect to our non-utility businesses has been to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets. In 2007, we have begun to exit the international marketplace. We reached agreements and announced plans to sell our ownership interests in businesses in the Middle East, Africa, India, and Latin America. We plan to use the proceeds from the pending asset sales to invest in our utility business and reduce parent company debt. We will continue to optimize the value of our North American non-utility assets. As a result of the reorganization at our utility business, we may incur charges in 2007. Completion of planned asset sales may also result in additional charges in 2007. We are unable to estimate the timing or extent of these charges. In January 2007, we reinstated a dividend on our common stock after a four- year suspension. The dividend is $0.05 per share for the first quarter of 2007. ELECTRIC UTILITY BUSINESS OUTLOOK GROWTH: Temperatures in the summer of 2006 were higher than historical averages yet lower than in the summer of 2005. Industrial activity declined during 2006 compared with 2005. These factors resulted in a decline of one percent in annual electric deliveries, excluding transactions with other wholesale market participants and other electric utilities. In 2007, we project electric deliveries to grow less than one-half of one percent compared to the levels experienced in 2006. This short-term outlook for 2007 assumes a small decline in industrial economic activity and normal weather conditions throughout the year. Over the next five years, we expect electric deliveries to grow at an average rate of less than 1.5 percent a year. However, this is dependent on a modestly growing customer base and a stabilizing Michigan economy after 2007. This growth rate includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. This growth rate reflects a long-range expected trend of growth. Growth from year to year may vary from this trend due to customer response to the following: - fluctuations in weather conditions and - changes in economic conditions, including utilization and expansion or contraction of manufacturing facilities. ELECTRIC RESERVE MARGIN: We are planning for a reserve margin of approximately 11 percent for summer 2007, or supply resources equal to 111 percent of projected firm summer peak load. Of the 2007 supply resources target of 111 percent, we expect 96 percent to come from our electric generating plants and long-term power purchase contracts, and 15 percent to come from other contractual arrangements. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2007 through 2010. As a result, we recognized an asset of $62 million for unexpired capacity and energy contracts at December 31, 2006. Upon the completion of the sale of the Palisades plant, the 15-year power purchase agreement with Entergy for 100 percent of the plant's current electric output will offset the reduction in the owned capacity represented by the Palisades plant. The MCV PPA is unaffected by the sale of our interest in the MCV Partnership. After September 15, 2007, we expect to exercise the regulatory out provision in the MCV PPA. If we are successful, the MCV Partnership has the right to terminate the MCV PPA, which could affect our reserve margin status. The MCV PPA represents 13 percent of our 2007 supply resources target. ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission service to us, increased substantially the transmission rates it charged us in 2006. The revenue collected by METC under those rates is subject to refund pending a FERC ruling. In January 2007, a settlement agreement among the parties was filed with the FERC resolving all issues associated with the rates METC charged us in 2006. This settlement, if approved by the FERC, will result in a refund of 2006 transmission charges of $18 million and a corresponding reduction of our power supply costs. In August 2006, the MPSC approved recovery of the increased METC electric transmission costs included in our 2006 PSCR plan. Due to the delay in recovery, we were unable to collect these increased costs in a timely manner CMS-28 and our cash flows from electric utility operations were affected negatively. For additional details, see Note 3, Contingencies, "Consumers' Electric Utility Rate Matters -- Power Supply Costs." CUSTOMER REVENUE OUTLOOK: Our electric utility customer base includes a mix of residential, commercial, and diversified industrial customers. In 2006, Michigan's automotive industry experienced negative developments resulting in manufacturing facility closures and restructurings. Our electric utility operations are not dependent upon a single customer, or even a few customers, and customers in the automotive sector constitute five percent of our total 2006 electric revenue. In addition, returning former ROA industrial customers benefit our electric utility revenue. However, we cannot predict the impact of current or possible future restructuring plans or possible future actions by our industrial customers. 21ST CENTURY ENERGY PLAN: In January 2006, the MPSC Staff issued a report on future electric capacity in the state of Michigan. The report indicated that existing generation resources are adequate in the short term, but could be insufficient to maintain reliability standards by 2009. The MPSC Staff recommended a review process for proposed new power plants. In January 2007, the chairman of the MPSC expanded on the capacity need work conducted by the MPSC Staff and proposed three major policy initiatives to the governor of Michigan. The initiatives involve the use of more renewable energy resources by all load- serving entities such as Consumers, the creation of an energy efficiency program, and a procedure for reviewing proposals to construct new generation facilities. The January 2007 proposal indicated that Michigan needs new baseload generation by 2015 and recommends regulatory measures to make it easier to predict customer demand and revenues. The proposed initiatives will require changes to current legislation. We will continue to participate as the MPSC, legislature, and other stakeholders addresses future electric capacity needs. ELECTRIC UTILITY BUSINESS UNCERTAINTIES Several electric business trends or uncertainties may affect our financial condition and future results of operations. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric operations. ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates. Clean Air Act: Compliance with the federal Clean Air Act and resulting regulations continues to be a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $835 million. These expenditures include installing selective catalytic reduction control technology on four of our coal-fired generating units. The key assumptions in the capital expenditure estimate include: - construction commodity prices, especially construction material and labor, - project completion schedules, - cost escalation factor used to estimate future years' costs, and - an AFUDC capitalization rate. Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 7.8 percent. As of December 2006, we have incurred $688 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $147 million of capital expenditures will be made in 2007 through 2011. In addition to modifying coal-fired electric generating plants, our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $3 million per year, which we expect to recover from our customers through the PSCR process. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances CMS-29 banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the coal-fired electric generating plants emit nitrogen oxide. Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. We plan to meet this rule by year-round operation of our selective catalytic reduction control technology units and installation of flue gas desulfurization scrubbers at an estimated total cost of $955 million, to be incurred by 2014. The rule may also require us to purchase additional nitrogen oxide allowances beginning in 2009. Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.4 percent. We will need to acquire additional sulfur dioxide emission allowances for an average annual cost of $21 million per year for the years 2011 through 2014. Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal- fired electric generating plants by 2010 and further reductions by 2018. Based on current technology, we anticipate our capital costs for mercury emissions reductions required by Phase I of the Clean Air Mercury Rule to be less than $50 million and expect these reductions to be implemented by 2010. Phase II requirements of the Clean Air Mercury Rule are not yet known and a cost estimate has not been determined. In April 2006, Michigan's governor announced a plan that would result in mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ on the details of these rules. We will develop a cost estimate when the details of these rules are determined. Greenhouse gases: Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, including carbon dioxide. We cannot predict whether any of these proposals will be enacted, or the specific requirements of any of these proposals and their effect on our future operations and financial results. In addition, the U.S. Supreme Court has agreed to hear a case claiming that the EPA is required by the Clean Air Act to consider regulating carbon dioxide emissions from automobiles. The EPA asserts that it lacks authority to regulate carbon dioxide emissions. If the Supreme Court finds that the EPA has authority to regulate carbon dioxide emissions in this case, it could result in new federal carbon dioxide regulations for other industries, including the utility industry. To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. We cannot estimate the potential effect of federal or state level greenhouse gas policy on our future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, we will continue to monitor greenhouse gas policy developments and assess and respond to their potential implications on our business operations. Water: In March 2004, the EPA issued rules that govern electric generating plant cooling water intake systems. The rules require significant reduction in fish killed by operating equipment. EPA compliance options in the rule were challenged in court. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The court's ruling is expected to increase significantly the cost of complying with this rule. However, the cost to comply will not be known until the EPA's reconsideration is complete. At this time, the EPA has not established a schedule to address the court decision. For additional details on electric environmental matters, see Note 3, Contingencies, "Consumers' Electric Utility Contingencies -- Electric Environmental Matters." COMPETITION AND REGULATORY RESTRUCTURING: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This is 3 percent of our total distribution load and represents a decrease of 46 percent of ROA load compared to the end of December 2005. In prior orders, the MPSC approved recovery of Stranded Costs incurred from 2002 through 2003 through a surcharge assessed to ROA customers. It is difficult to predict future ROA customer trends and their impact on the timely recovery of our Stranded Costs. CMS-30 ELECTRIC RATE CASE: We expect to file an electric rate case in March 2007. For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, "Consumers' Electric Utility Rate Matters." OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES THE MCV PARTNERSHIP: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990. Sale of our Interest in the MCV Partnership and the FMLP: In November 2006, we sold 100 percent of our ownership interest in MCV GP II (the successor of CMS Midland, Inc.) and 100 percent of our ownership interest in the stock of CMS Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments for $60.5 million. These Consumers subsidiaries held our interests in the MCV Partnership and the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments, to pay $85 million, subject to certain conditions and reimbursement rights, if Dow terminates an agreement under which the MCV Partnership provides it power and steam. The purchaser secured their reimbursement obligation with an irrevocable letter of credit of up to $85 million. The MCV PPA and the associated customer rates are unaffected by the sale. The transaction resulted in a net after-tax loss of $41 million, which includes the reversal of $30 million, into earnings, of certain cumulative amounts of the MCV Partnership derivative fair value changes that we accounted for in AOCL. For additional details on the sale of our interests in the MCV Partnership and the FMLP, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations and Note 6, Financial and Derivative Instruments, "Derivative Contracts Associated with the MCV Partnership." Underrecoveries related to the MCV PPA: The cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we incurred cash underrecoveries of capacity and fixed energy payments of $57 million in 2006 and we estimate cash underrecoveries of $39 million in 2007. However, we use the direct savings from the RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. This action would eliminate our underrecoveries of capacity and fixed energy payments. The MCV Partnership has notified us that it takes issue with our intended exercise of the regulatory out provision after September 15, 2007. We believe that the provision is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out provision, the MCV Partnership has the right to terminate the MCV PPA. If the MCV Partnership terminates the MCV PPA, we would seek to replace the lost capacity to maintain an adequate electric reserve margin. This could involve entering into a new PPA and (or) entering into electric capacity contracts on the open market. We cannot predict our ability to enter into such contracts at a reasonable price. We are also unable to predict regulatory approval of the terms and conditions of such contracts, or that the MPSC would allow full recovery of our incurred costs. For additional details on the MCV Partnership, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The MCV PPA." NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006, we reached an agreement to sell Palisades to Entergy for $380 million and pay Entergy $30 million to assume ownership and responsibility for the Big Rock Independent Spent Fuel Storage Installation (ISFSI). Under the agreement, if the transaction does not close by March 1, 2007, there is a reduction in the purchase price of approximately $80,000 per day, with additional costs if the transaction does not close by June 1, 2007. Based on the MPSC's published schedule for the contested case proceedings regarding this transaction, we target to close on the transaction in the second quarter of 2007. We estimate that the Palisades sale will result in a $31 million premium above the Palisades asset values at the anticipated closing date after accounting for estimated sales-related costs. We expect that this premium will benefit our customers. Entergy will assume responsibility for the future decommissioning of the plant and for storage and disposal of spent nuclear fuel located at the Palisades and the Big Rock ISFSI sites. At the anticipated date of close, we estimate decommissioning trust assets to be $605 million. We will retain $205 million of these funds at the time of close and CMS-31 will be entitled to receive a return of an additional $147 million, pending either a favorable federal tax ruling regarding the release of the funds or, if no such ruling is issued, after decommissioning of the Palisades site is complete. These estimates fluctuate based on existing market conditions. The disposition of the retained and receivable nuclear decommissioning funds is subject to regulatory approval. We expect to use the proceeds to benefit our customers. We plan to use the cash that we retain from the sale to reduce utility debt. As part of the transaction, Entergy will sell us 100 percent of the plant's output up to its current capacity of 798 MW under a 15-year power purchase agreement. The sale is subject to various regulatory approvals, including the MPSC's approval of the power purchase agreement and the NRC's approval of the transfer of the operating license to Entergy and other related matters. In February 2007, the FERC issued an order approving the sale of power to us under the power purchase agreement and granted other related approvals, with what we believe are minor exceptions and conditions that we believe can be adequately accepted. In October 2006, the Federal Trade Commission issued a notice that neither it nor the DOJ's Antitrust Division plan to take enforcement action on the sale. The final purchase price will be subject to various closing adjustments such as working capital and capital expenditure adjustments, adjustments for nuclear fuel usage and inventory, and the date of closing. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur. We have notified the NMC that we plan to terminate the NMC's operation of Palisades, if the sale is completed, which would require us to pay the NMC an estimated $12 million. Due to the regulatory approvals pending, we have not recorded this contingent obligation. For additional details on sale of Palisades and the Big Rock ISFSI, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase Agreement." Big Rock: Dismantlement and decommissioning of the Big Rock Plant was completed in August 2006. In November 2006, we requested the NRC to release approximately 435 acres from the terms of our operating license. In January 2007, the NRC approved our request to release the 435 acres for unrestricted public use. An area of approximately 107 acres including the Big Rock ISFSI, where eight casks loaded with spent fuel and other high-level radioactive material are stored, is part of the sale of nuclear assets as previously described. Palisades: The amount of spent nuclear fuel at Palisades exceeds the plant's temporary onsite wet storage pool capacity. We are using dry casks for temporary onsite dry storage to supplement the wet storage pool capacity. Palisades' original license from the NRC was scheduled to expire in 2011. In March 2005, the NMC, which operates the Palisades plant, applied for a 20- year license renewal for the plant on behalf of Consumers. In January 2007, the NRC renewed the Palisades operating license for 20 years, extending it to 2031. For additional details on nuclear plant decommissioning at Big Rock and Palisades, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Plant Decommissioning." GAS UTILITY BUSINESS OUTLOOK GROWTH: In 2007, we project gas deliveries will decline slightly, on a weather-adjusted basis, from 2006 levels due to continuing conservation and overall economic conditions in the state of Michigan. Over the next five years, we expect gas deliveries to decline by less than one-half of one percent annually. Actual gas deliveries in future periods may be affected by: - fluctuations in weather conditions, - use by independent power producers, - competition in sales and delivery, - changes in gas commodity prices, - Michigan economic conditions, - the price of competing energy sources or fuels, CMS-32 - gas consumption per customer, and - improvements in gas appliance efficiency. GAS UTILITY BUSINESS UNCERTAINTIES Several gas business trends or uncertainties may affect our future financial results and financial condition. These trends or uncertainties could have a material impact on future revenues or income from gas operations. GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 3, Contingencies, "Consumers' Gas Utility Contingencies -- Gas Environmental Matters." GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudency in annual plan and reconciliation proceedings. For additional details on gas cost recovery, see Note 3, Contingencies, "Consumers' Gas Utility Rate Matters -- Gas Cost Recovery." GAS DEPRECIATION: We are required to file our next gas depreciation case with the MPSC within 90 days after the MPSC issuance of a final order in the pending case related to ARO accounting. We cannot predict when the MPSC will issue a final order in the ARO accounting case. If a final order in our next gas depreciation case is not issued concurrently with a final order in a general gas rate case, the MPSC may incorporate the results of the depreciation case into general gas rates through use of a surcharge mechanism (which may be either positive or negative). 2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity along with an $88 million annual increase in our gas delivery and transportation rates. We have proposed the use of a Revenue Decoupling and Conservation Incentive Mechanism for residential and general service rate classes to help assure a reasonable opportunity to recover costs that do not fluctuate with volumetric changes. ENTERPRISES OUTLOOK Our primary focus with respect to our non-utility businesses is to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets. In January 2007, we signed a binding letter of intent with Lucid Energy, LLC to sell a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets for $180 million. The assets being sold include all of our electric generating plant interests in Argentina and our interest in the TGM natural gas pipeline business in Argentina. We will maintain our interest in the TGN natural gas business in Argentina, which remains subject to a potential sale to the government of Argentina. We presently plan to retain our interest in TGN until such time as any interest or option held by the Argentine government expires. In Michigan, the sale includes the Antrim natural gas processing plant, 155 miles of associated gathering lines, and interests in three special purpose gas transmission pipelines that total 110 miles. We expect to close on the sale in the first half of 2007. In February 2007, we entered into an Agreement of Purchase and Sale with TAQA to sell our ownership interest in businesses in the Middle East, Africa, and India for $900 million. Businesses included in the sale are Taweelah, Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We expect to close on the sale in the middle of 2007. In February 2007, we signed a memorandum of understanding with Petroles de Venezuela, S.A. to sell our ownership interest in SENECA and certain associated generating equipment for $106 million. We expect to close on the sale by March 31, 2007. We anticipate gross proceeds from these sale transactions to total approximately $1.186 billion. The book value of these assets at December 31, 2006 is approximately $913 million. The asset book values will vary between December 31, 2006 and each transaction's closing date. Final book value is dependent upon the timing of closing, CMS-33 results of operations for certain of the assets up to closing, and other factors. The cumulative currency translation losses at December 31, 2006 related to all of our business in Argentina are $256 million, net of tax. We also announced plans to conduct an auction to sell our Atacama combined gas pipeline and power generation businesses in Argentina and Chile, our electric generating plant in Jamaica, and our CPEE electric distribution business in Brazil. We expect to complete the sale of these businesses by the end of 2007. Our pending asset sales are subject to the receipt of all necessary governmental, lender and partner approvals. As we restructure our Enterprises business, we will continue to optimize the value of our North American non- utility assets. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. UNCERTAINTIES: Trends or uncertainties that could have a material impact on our consolidated income, cash flows, or balance sheet and credit improvement include: - successful close of the sale of our ownership interests in businesses in the Middle East, Africa, and India, - successful entry into a definitive purchase and sale agreement and closing of the proposed sale of certain of our Argentine assets and our northern Michigan non-utility natural gas assets, - successful close of the sale of our ownership interest in SENECA, - the outcome of the planned auction of other generation and distribution assets in South America, including the following uncertainties which could affect the value of these businesses: - changes in available gas supplies or Argentine government regulations that could further restrict natural gas exports to our GasAtacama electric generating plant, - changes in exchange rates or in local economic or political conditions, - changes in foreign taxes or laws or in governmental or regulatory policies that could reduce significantly the tariffs charged and revenues recognized by certain foreign subsidiaries, or increase expenses, and - imposition of stamp taxes on South American contracts that could increase project expenses substantially, - impact of indemnity and environmental remediation obligations at Bay Harbor, and - changes in commodity prices and interest rates on certain derivative contracts that do not qualify for hedge accounting and must be marked to market through earnings. GASATACAMA: In 2004, the Argentine government authorized the restriction of exports of natural gas to Chile, giving priority to domestic demand in Argentina. This restriction had a harmful effect on GasAtacama's earnings since GasAtacama's gas-fired electric generating plant is located in Chile and uses Argentine gas for fuel. Bolivia agreed to export 4 million cubic meters of gas per day to Argentina. With the Bolivian gas supply, Argentina relaxed its export restrictions to GasAtacama. In May 2006, the Bolivian government nationalized the natural gas industry and raised prices under its existing gas export contracts. Gas supply to GasAtacama was restricted as Argentina and Bolivia renegotiated the price for gas. In July 2006, Argentina agreed to increase the price it paid for gas from Bolivia. Argentina also announced that it would recover all of this price increase by a special tax on its gas exports. This increased the risk and cost of GasAtacama's fuel supply. In August 2006, a major gas supplier notified GasAtacama that it would no longer deliver gas to GasAtacama under the Argentine government's current policy. In the third quarter of 2006, we performed an impairment analysis and recorded an impairment charge of $239 million ($169 million, net of tax and minority interest) in our Consolidated Statements of Income (Loss). At December 31, 2006, the carrying value of our investment in GasAtacama was $117 million. This remaining value continues to be exposed to the threat of a complete gas restriction by Argentina and the inability of GasAtacama to pass through the increased costs associated with such a restriction to its regulated customers. Therefore, if conditions do not improve, the result could be a further impairment of our investment in GasAtacama. CMS-34 In February 2007, we announced plans to conduct an auction to sell GasAtacama. We expect to complete the sale by the end of 2007. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. PRAIRIE STATE: In October 2006, we signed agreements with Peabody Energy to co-develop the Prairie State Energy Campus (Prairie State), a 1,600 MW power plant and coal mine in southern Illinois. Enterprises and Peabody Energy will co-develop and each own 15 percent of Prairie State indirectly through a jointly owned limited liability company. Enterprises will serve as lead developer, construction manager, and operator of the mine-mouth power plant. Peabody Energy will be lead developer of the mine that will fuel the power plant. Financial close of the project is contingent upon Peabody Energy and Enterprises being able to secure: - non-recourse project financing, - an engineering, procurement, and construction contract for the power plant, and - long-term power purchase agreements which will include protection against unknown future carbon dioxide regulation, or hedging contracts for a substantial portion of Enterprises' and Peabody Energy's share of the project's output. Construction of the first 800 MW generating unit is expected to take about four years to complete and the second 800 MW unit will be completed shortly afterward. We expect to finance our projected equity investment of approximately $200 million with a bridge loan until the completion of construction. OTHER OUTLOOK RULES REGARDING BILLING PRACTICES: In December 2006, the MPSC issued proposed rule changes to residential customer billing standards and practices. These changes, if adopted, would provide additional protection to low-income customers during the winter heating season that will be defined as November 1 through March 31, extend the time between billing date and due date from 17 days to 22 days, and eliminate estimated metering readings unless actual readings are not feasible. We are presently evaluating the impacts of these proposed rules and are working with other Michigan utilities in providing comments to the MPSC regarding the proposed rule changes. LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an investigation by the DOJ regarding round-trip trading transactions by CMS MST. Also, we are named as a party in various litigation matters including, but not limited to, securities class action lawsuits and several lawsuits regarding alleged false natural gas price reporting and price manipulation. Additionally, the SEC is investigating the actions of former CMS Energy subsidiaries in relation to Equatorial Guinea. For additional details regarding these and other matters, see Note 3, Contingencies and Part I, Item 3. Legal Proceedings. FIXED PRICE CONTRACTS: DIG and CMS ERM are parties to long-term requirements contracts to provide steam and/or electricity based on a fixed price schedule. The price of natural gas, the primary fuel used by DIG, is volatile and has increased substantially in recent years. Because the prices charged under DIG's contracts do not reflect current natural gas prices, DIG's and CMS ERM's financial performance has been impacted negatively. However, since not all of its capacity is committed under these contracts, DIG has been able to sell a portion of its electric capacity and/or energy on the market at a profit, or, through CMS ERM, engage in a hedging strategy to minimize its losses. DIG and CMS ERM may take various actions such as seeking restructuring of the contracts. CMS Energy may also take other measures to address the unfavorable returns. PENSION REFORM: In August 2006, the President signed into law the Pension Protection Act of 2006. The bill reforms the funding rules for employer-provided pension plans, effective for plan years beginning after 2007. As a result of this bill, we expect to reduce our contributions to the Pension Plan over the next 10 years by a present value amount of $56 million. IMPLEMENTATION OF NEW ACCOUNTING STANDARDS SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was CMS-35 effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our consolidated results of operations when it became effective. We applied the additional guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R). STAFF ACCOUNTING BULLETIN NO. 108, CONSIDERING THE EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL STATEMENTS: SAB No. 108 was adopted on December 31, 2006. The standard clarifies how we should assess the materiality of prior period financial statement errors in the current period. Prior to the adoption of this standard,we used the "iron- curtain" method to quantify the effects of prior period financial statement errors. The iron-curtain method focuses on the effects of correcting the period- end balance sheet with less emphasis on the effects the correction would have on our consolidated income statement. This standard requires quantification of financial statement errors based on their effect on each of our consolidated financial statements. The adoption of this standard did not have an effect on our financial position or results of operations. 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): In September 2006, the FASB issued SFAS No. 158. This standard requires us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Upon implementation of this standard, we recorded an additional postretirement benefit liability of $647 million, a regulatory asset of $680 million and a reduction of $7 million to AOCL, after tax. This standard also requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of this provision of the standard will have a material effect on our consolidated financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008. NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006, the FASB issued FIN 48, effective for us in January 2007. This interpretation provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management's best judgment, it is greater than 50 percent likely that the taxing authority will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return. Our policy is to include interest and penalties accrued on uncertain tax positions as part of the related tax liability on our consolidated balance sheet and as part of the income tax expense in our consolidated income statement. The impact from adopting FIN 48 should be recorded as a cumulative adjustment to the beginning retained earnings balance and a corresponding adjustment to a current or non-current tax liability. Although we have not yet determined the full effect of FIN 48, we believe that any reduction to our retained earnings as of January 1, 2007 will be less than $30 million. SFAS NO. 157, FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a revised definition of "fair value" and gives guidance on how to measure the fair value of assets and liabilities. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value in any new circumstances. However, additional disclosures will be required on the impact and reliability of fair value measurements reflected in our consolidated financial statements. The standard will also eliminate the existing prohibition of recognizing "day one" gains or losses on derivative instruments, and will generally require such gains and losses to be recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS No. 157. We currently do not hold any derivatives that would involve day one gains or losses. CMS-36 SFAS NO. 159, THE FAIR VALUE OPTION FOR FINANCIAL ASSETS AND FINANCIAL LIABILITIES, INCLUDING AN AMENDMENT TO FASB STATEMENT NO. 115: In February 2007, the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard will give us the option to select certain financial instruments and other items, which otherwise are not required to be measured at fair value, and measure those items at fair value. If we choose to elect the fair value option for an item, we would recognize unrealized gains and losses associated with changes in the fair value of the item over time. The statement will also require disclosures for items for which the fair value option has been elected. We are presently evaluating whether we will choose to elect the fair value option for any financial instruments or other items. CMS-37 CMS Energy Corporation CONSOLIDATED STATEMENTS OF INCOME (LOSS)
YEARS ENDED DECEMBER 31 ------------------------ 2006 2005 2004 ---- ---- ---- IN MILLIONS OPERATING REVENUE......................................... $6,810 $6,288 $5,472 EARNINGS FROM EQUITY METHOD INVESTEES..................... 89 125 115 OPERATING EXPENSES Fuel for electric generation............................ 984 720 774 Fuel costs mark-to-market at the MCV Partnership........ 204 (200) 19 Purchased and interchange power......................... 829 546 344 Cost of gas sold........................................ 2,131 2,297 1,786 Other operating expenses................................ 1,225 1,105 954 Maintenance............................................. 326 249 256 Depreciation, depletion and amortization................ 576 525 431 General taxes........................................... 198 261 270 Asset impairment charges................................ 459 1,184 160 ------ ------ ------ 6,932 6,687 4,994 ------ ------ ------ OPERATING INCOME (LOSS)................................... (33) (274) 593 OTHER INCOME (DEDUCTIONS) Accretion expense....................................... (4) (18) (23) Gain on asset sales, net................................ 79 6 52 Interest and dividends.................................. 86 66 27 Regulatory return on capital expenditures............... 26 4 113 Foreign currency gains (losses), net.................... -- (7) (3) Other income............................................ 33 36 27 Other expense........................................... (19) (30) (15) ------ ------ ------ 201 57 178 ------ ------ ------ FIXED CHARGES Interest on long-term debt.............................. 468 477 502 Interest on long-term debt -- related parties........... 15 29 58 Other interest.......................................... 33 16 44 Capitalized interest.................................... (10) (38) 25 Preferred dividends of subsidiaries..................... 5 5 5 ------ ------ ------ 511 489 634 ------ ------ ------ INCOME (LOSS) BEFORE MINORITY INTERESTS (OBLIGATIONS), NET..................................................... (343) (706) 137 MINORITY INTERESTS (OBLIGATIONS), NET..................... (100) (440) 15 ------ ------ ------ INCOME (LOSS) BEFORE INCOME TAXES......................... (243) (266) 122 INCOME TAX BENEFIT........................................ (158) (168) (5) ------ ------ ------ INCOME (LOSS) FROM CONTINUING OPERATIONS.................. (85) (98) 127 INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $2 TAX EXPENSE IN 2006, $8 TAX EXPENSE IN 2005 AND $18 TAX EXPENSE IN 2004......................................... 6 14 (4) ------ ------ ------ INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING.............................................. (79) (84) 123 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR RETIREMENT BENEFITS, NET OF $1 TAX BENEFIT......................... -- -- (2) ------ ------ ------ NET INCOME (LOSS)......................................... (79) (84) 121 PREFERRED DIVIDENDS....................................... 11 10 11 ------ ------ ------ NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS........ $ (90) $ (94) $ 110 ====== ====== ======
CMS-38
YEARS ENDED DECEMBER 31 ------------------------ 2006 2005 2004 ------ ------ ------ IN MILLIONS, EXCEPT PER SHARE AMOUNTS CMS ENERGY NET INCOME (LOSS) Net Income (Loss) Available to Common Stockholders... $ (90) $ (94) $ 110 ====== ====== ====== BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE Income (Loss) from Continuing Operations............. $(0.44) $(0.51) $ 0.68 Income (Loss) from Discontinued Operations........... 0.03 0.07 (0.02) Loss from Change in Accounting....................... -- -- (0.01) ------ ------ ------ Net Income (Loss) Attributable to Common Stock....... $(0.41) $(0.44) $ 0.65 ====== ====== ====== DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE Income (Loss) from Continuing Operations............. $(0.44) $(0.51) $ 0.67 Income (Loss) from Discontinued Operations........... 0.03 0.07 (0.02) Loss from Change in Accounting....................... -- -- (0.01) ------ ------ ------ Net Income (Loss) Attributable to Common Stock....... $(0.41) $(0.44) $ 0.64 ====== ====== ====== DIVIDENDS DECLARED PER COMMON SHARE..................... $ -- $ -- $ -- ====== ====== ======
The accompanying notes are an integral part of these statements. CMS-39 CMS Energy Corporation CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31 ------------------------- 2006 2005 2004 ---- ---- ---- IN MILLIONS CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss)...................................... $ (79) $ (84) $ 121 Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation, depletion and amortization (includes nuclear decommissioning of $6 per year)........... 576 525 431 Deferred income taxes and investment tax credit..... (271) (199) 67 Regulatory return on capital expenditures........... (26) (4) (113) Minority interests (obligations), net............... (100) (440) 15 Fuel costs mark-to-market at the MCV Partnership.... 204 (200) 19 Asset impairment charges............................ 459 1,184 160 Capital lease and other amortization................ 44 40 28 Accretion expense................................... 4 18 23 Bad debt expense.................................... 28 23 19 Gain on the sale of assets (includes discontinued operations)....................................... (79) (20) (50) Cumulative effect of accounting changes............. -- -- 2 Earnings from equity method investees............... (89) (125) (115) Cash distributions from equity method investees..... 75 108 27 Changes in other assets and liabilities: Increase in accounts receivable, notes receivable, and accrued revenues........................... (91) (311) (144) Increase in inventories........................... (105) (245) (109) Increase (decrease) in accounts payable........... (43) 170 109 Increase in legal settlement liability............ 200 -- -- Increase in accrued taxes......................... 3 19 16 Increase (decrease) in accrued expenses........... 36 (11) 21 Increase (decrease) in the MCV Partnership gas supplier funds on deposit...................... (147) 173 15 Decrease (increase) in other current and non- current assets................................. 45 (37) (117) Increase (decrease) in other current and non- current liabilities............................ 44 15 (72) ----- ------- ------- Net cash provided by operating activities.............. 688 599 353 ----- ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excludes assets placed under capital lease)...................................... (670) (593) (525) Investments in partnerships and unconsolidated subsidiaries........................................ -- -- (71) Cost to retire property................................ (78) (27) (28) Restricted cash and restricted short-term investments.. 124 (151) 145 Investments in Electric Restructuring Implementation Plan................................................ -- -- (7) Investments in nuclear decommissioning trust funds..... (21) (6) (6) Proceeds from nuclear decommissioning trust funds...... 22 39 36 Proceeds from short-term investments................... -- 295 2,267 Purchase of short-term investments..................... -- (186) (2,376) Maturity of the MCV Partnership restricted investment securities held-to-maturity......................... 130 318 675 Purchase of the MCV Partnership restricted investment securities held-to-maturity......................... (131) (270) (674) Proceeds from sale of assets........................... 69 61 219 Cash relinquished from sale of assets.................. (148) -- -- Decrease (increase) in non-current notes receivable.... (50) 1 (10) Other investing........................................ 2 25 8 ----- ------- ------- Net cash used in investing activities............... (751) (494) (347) ----- ------- -------
CMS-40
YEARS ENDED DECEMBER 31 ------------------------- 2006 2005 2004 ---- ---- ---- IN MILLIONS CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from notes, bonds, and other long-term debt... 100 1,385 1,392 Issuance of common stock............................... 8 295 290 Retirement of bonds and other long-term debt........... (493) (1,509) (1,631) Payment of preferred stock dividends................... (11) (11) (11) Payment of capital lease and finance lease obligations......................................... (26) (29) (44) Increase in notes payable.............................. 2 -- -- Debt issuance costs, financing fees, and other......... (14) (57) (39) ----- ------- ------- Net cash provided by (used in) financing activities........................................ (434) 74 (43) ----- ------- ------- EFFECT OF EXCHANGE RATES ON CASH......................... 1 (1) -- ----- ------- ------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..... (496) 178 (37) CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB INTERPRETATION NO. 46 CONSOLIDATION.................... -- -- 174 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD........... 847 669 532 ----- ------- ------- CASH AND CASH EQUIVALENTS, END OF PERIOD................. $ 351 $ 847 $ 669 ===== ======= ======= OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE: CASH TRANSACTIONS Interest paid (net of amounts capitalized)............. $ 487 $ 454 $ 601 Income taxes paid (net of refunds)..................... -- (9) -- Pension and OPEB cash contribution..................... 69 63 63 NON-CASH TRANSACTIONS Other assets placed under capital lease................ $ 7 $ 12 $ 3 ----- ------- -------
The accompanying notes are an integral part of these statements. CMS-41 CMS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS
DECEMBER 31 ----------------- 2006 2005 ---- ---- IN MILLIONS ASSETS PLANT AND PROPERTY (AT COST) Electric utility............................................ $ 8,504 $ 8,204 Gas utility................................................. 3,273 3,151 Enterprises................................................. 834 1,068 Other....................................................... 31 25 ------- ------- 12,642 12,448 Less accumulated depreciation, depletion and amortization... 5,317 5,123 ------- ------- 7,325 7,325 Construction work-in-progress............................... 651 520 ------- ------- 7,976 7,845 ------- ------- INVESTMENTS Enterprises................................................. 588 712 Other....................................................... 10 13 ------- ------- 598 725 ------- ------- CURRENT ASSETS Cash and cash equivalents at cost, which approximates market................................................... 351 847 Restricted cash and restricted short-term investments at cost, which approximates market.......................... 71 198 Accounts receivable, notes receivable, and accrued revenue, less allowances of $33 in 2006 and $31 in 2005........... 808 845 Accounts receivable, dividends receivable, and notes receivable -- related parties............................ 67 54 Inventories at average cost Gas in underground storage............................... 1,129 1,069 Materials and supplies................................... 102 96 Generating plant fuel stock.............................. 126 110 Price risk management assets................................ 45 113 Regulatory assets -- postretirement benefits................ 19 19 Derivative instruments...................................... -- 242 Deferred income taxes....................................... 155 -- Deferred property taxes..................................... 150 160 Prepayments and other....................................... 120 167 ------- ------- 3,143 3,920 ------- ------- NON-CURRENT ASSETS Regulatory assets Securitized costs........................................ 514 560 Additional minimum pension............................... -- 399 Postretirement benefits.................................. 1,131 116 Customer Choice Act...................................... 190 222 Other.................................................... 462 484 Price risk management assets................................ 19 165 Nuclear decommissioning trust funds......................... 602 555 Goodwill.................................................... 26 27 Notes receivable -- related parties......................... 125 187 Notes receivable............................................ 246 187 Other....................................................... 339 649 ------- ------- 3,654 3,551 ------- ------- TOTAL ASSETS.................................................. $15,371 $16,041 ======= =======
CMS-42
DECEMBER 31 ----------------- 2006 2005 ---- ---- IN MILLIONS STOCKHOLDERS' INVESTMENT AND LIABILITIES CAPITALIZATION Common stockholders' equity Common stock, authorized 350.0 shares; outstanding 222.8 shares in 2006 and 220.5 shares in 2005.................. $ 2 $ 2 Other paid-in capital....................................... 4,468 4,436 Accumulated other comprehensive loss........................ (318) (288) Retained deficit............................................ (1,918) (1,828) ------- ------- 2,234 2,322 Preferred stock of subsidiary............................... 44 44 Preferred stock............................................. 261 261 Long-term debt.............................................. 6,202 6,800 Long-term debt -- related parties........................... 178 178 Non-current portion of capital and finance lease obligations.............................................. 42 308 ------- ------- 8,961 9,913 ------- ------- MINORITY INTERESTS............................................ 91 333 ------- ------- CURRENT LIABILITIES Current portion of long-term debt, capital and finance leases................................................... 564 316 Current portion of long-term debt -- related parties........ -- 129 Notes payable............................................... 2 -- Accounts payable............................................ 564 597 Accounts payable -- related parties......................... 2 16 Accrued interest............................................ 130 145 Accrued taxes............................................... 331 331 Price risk management liabilities........................... 70 80 Current portion of gas supply contract obligations.......... -- 10 Deferred income taxes....................................... -- 55 MCV Partnership gas supplier funds on deposit............... -- 193 Legal settlement liability.................................. 200 -- Other....................................................... 293 262 ------- ------- 2,156 2,134 ------- ------- NON-CURRENT LIABILITIES Regulatory liabilities Regulatory liabilities for cost of removal............... 1,166 1,120 Income taxes, net........................................ 539 455 Other regulatory liabilities............................. 249 178 Postretirement benefits..................................... 1,071 382 Deferred income taxes....................................... 120 297 Deferred investment tax credit.............................. 62 67 Asset retirement obligations................................ 500 496 Price risk management liabilities........................... 31 161 Gas supply contract obligations............................. -- 61 Other....................................................... 425 444 ------- ------- 4,163 3,661 ------- ------- Commitments and Contingencies (Notes 3,4,6,9 and 11) TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES................ $15,371 $16,041 ======= =======
The accompanying notes are an integral part of these statements. CMS-43 CMS Energy Corporation Consolidated Statements of Common Stockholders' Equity
YEARS ENDED DECEMBER 31 --------------------------------------------------------- 2006 2005 2004 2006 2005 2004 ---- ---- ---- ---- ---- ---- NUMBER OF SHARES IN IN MILLIONS THOUSANDS COMMON STOCK At beginning and end of period... $ 2 $ 2 $ 2 ------- ------- ------- OTHER PAID-IN CAPITAL At beginning of period........... 220,497 194,997 161,130 4,436 4,140 3,846 Common stock repurchased......... (98) (88) (43) (2) (1) (1) Common stock reacquired.......... (59) -- (270) -- -- (5) Common stock issued.............. 2,375 25,493 34,180 33 296 301 Common stock reissued............ 68 95 -- 1 1 -- Issuance cost of preferred stock......................... -- -- -- -- -- (1) ------- ------- ------- ------- ------- ------- At end of period............ 222,783 220,497 194,997 4,468 4,436 4,140 ------- ------- ------- ------- ------- ------- ACCUMULATED OTHER COMPREHENSIVE LOSS Retirement benefits liability At beginning of period........ (19) (17) -- Retirement benefits liability adjustments(a).............. 3 (2) (17) Adjustment to initially apply FASB Statement No. 158...... (7) -- -- ------- ------- ------- At end of period............ (23) (19) (17) ------- ------- ------- Investments At beginning of period........ 9 9 8 Unrealized gain on investments(a).............. 5 -- 1 ------- ------- ------- At end of period............ 14 9 9 ------- ------- ------- Derivative instruments At beginning of period........ 35 (9) (8) Unrealized gain (loss) on derivative instruments(a)... (15) 51 5 Reclassification adjustments included in net income (loss)(a)................... (32) (7) (6) ------- ------- ------- At end of period............ (12) 35 (9) ------- ------- ------- FOREIGN CURRENCY TRANSLATION At beginning of period........... (313) (319) (419) Loy Yang sale.................... -- -- 110 Other foreign currency translations(a)............... 16 6 (10) ------- ------- ------- At end of period.............. (297) (313) (319) ------- ------- ------- At end of period............ (318) (288) (336) ------- ------- ------- RETAINED DEFICIT At beginning of period........... (1,828) (1,734) (1,844) Net income (loss)(a)............. (79) (84) 121 Preferred stock dividends declared...................... (11) (10) (11) ------- ------- ------- At end of period............ (1,918) (1,828) (1,734) ------- ------- ------- TOTAL COMMON STOCKHOLDERS' EQUITY.. $ 2,234 $ 2,322 $ 2,072 ======= ======= =======
CMS-44
YEARS ENDED DECEMBER 31 ------------------- 2006 2005 2004 ---- ---- ---- IN MILLIONS (A) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS): Retirement benefits liability Retirement benefits liability adjustments, net of tax (tax benefit) of $1 in 2006, $(1) in 2005 and $(9) in 2004............................................ $ 3 $ (2) $(17) Investments Unrealized gain on investments, net of tax of $2 in 2006, $- in 2005 and $1 in 2004.................... 5 -- 1 Derivative instruments Unrealized gain (loss) on derivative instruments, net of tax (tax benefit) of $(11) in 2006, $29 in 2005 and $12 in 2004.................................... (15) 51 5 Reclassification adjustments included in net income (loss), net of tax benefit of $(19) in 2006, $(9) in 2005 and $(6) in 2004........................... (32) (7) (6) Loy Yang sale........................................... -- -- 110 Other foreign currency translations..................... 16 6 (10) Net income (loss)....................................... (79) (84) 121 ----- ---- ---- Total Other Comprehensive Income (Loss)............... $(102) $(36) $204 ===== ==== ====
The accompanying notes are an integral part of these statements. CMS-45 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES CORPORATE STRUCTURE: CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international diversified energy businesses including independent power production, electric distribution, and natural gas transmission, storage and processing. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises. PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include CMS Energy, Consumers, Enterprises, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with FASB Interpretation No. 46(R). We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. We eliminate intercompany transactions and balances. USE OF ESTIMATES: We prepare our consolidated financial statements in conformity with U.S. GAAP. We are required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates. We record estimated liabilities for contingencies in our consolidated financial statements when it is probable that a loss will be incurred in the future as a result of a current event, and when an amount can be reasonably estimated. For additional details, see Note 3, Contingencies. REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the transportation, processing, and storage of natural gas when services are provided. We record sales tax on a net basis and exclude it from revenues. We recognize revenues on sales of marketed electricity, natural gas, and other energy products at delivery. We recognize mark-to-market changes in the fair values of energy trading contracts that qualify as derivatives as revenues in the periods in which the changes occur. ACCOUNTING FOR MISO TRANSACTIONS: CMS ERM accounts for MISO transactions on a net basis for all of the generating units for which CMS ERM markets power. CMS ERM allocates other fixed costs associated with MISO settlements back to the generating units and records billing adjustments when it receives invoices. Consumers accounts for MISO transactions on a net basis for all of its generating units combined. Consumers records billing adjustments when it receives invoices and records an expense accrual for future adjustments based on historical experience. ACCRETION EXPENSE: CMS ERM engaged in prepaid sales arrangements to provide natural gas to various entities over periods of up to 12 years at predetermined price levels. CMS ERM established a liability for those outstanding obligations equal to the discounted present value of the contracts, and hedged its exposures under those arrangements. As CMS ERM fulfilled its obligations under the contracts, it recognized revenues upon the delivery of natural gas, recorded a reduction to the outstanding obligation, and recognized accretion expense. In August 2006, CMS ERM extinguished its outstanding obligations for $70 million, which included a $6 million loss on extinguishment. CAPITALIZED INTEREST: We capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest for the period is limited to the actual interest cost incurred. Our regulated businesses capitalize AFUDC on regulated construction projects and include such amounts in plant in service. CASH EQUIVALENTS AND RESTRICTED CASH: Cash equivalents are all liquid investments with an original maturity of three months or less. CMS-46 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) At December 31, 2006, our restricted cash on hand was $71 million. We classify restricted cash dedicated for repayment of Securitization bonds as a current asset, as the related payments occur within one year. COLLECTIVE BARGAINING AGREEMENTS: At December 31, 2006, the Utility Workers of America Union represented approximately 45 percent of Consumers employees. The Union represents Consumers' operating, maintenance, and construction employees and call center employees. DETERMINATION OF PENSION MRV OF PLAN ASSETS: We determine the MRV for pension plan assets, as defined in SFAS No. 87, as the fair value of plan assets on the measurement date, adjusted by the gains or losses that will not be admitted into MRV until future years. We reflect each year's assets gain or loss in MRV in equal amounts over a five-year period beginning on the date the original amount was determined. We use the MRV in the calculation of net pension cost. EARNINGS PER SHARE: We calculate basic and diluted EPS using the weighted average number of shares of common stock and dilutive potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted EPS, includes the effects of dilutive stock options, warrants and convertible securities. We compute the effect on potential common stock using the treasury stock method or the if-converted method, as applicable. Diluted EPS excludes the impact of antidilutive securities, which are those securities resulting in an increase in EPS or a decrease in loss per share. For earnings per share computation, see Note 5, Earnings Per Share. EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL STATEMENTS: SAB No. 108 was adopted on December 31, 2006. The standard clarifies how we should assess the materiality of prior period financial statement errors in the current period. Prior to the adoption of this standard, we used the "iron-curtain" method to quantify the effects of prior period financial statement errors. The iron-curtain method focuses on the effects of correcting the period-end balance sheet with less emphasis on the effects the correction would have on our income statement. This standard requires quantification of financial statement errors based on their effect on each of our consolidated financial statements. The adoption of this standard did not have an effect on our financial position or results of operations. FINANCIAL AND DERIVATIVE INSTRUMENTS: We record debt and equity securities classified as available-for-sale at fair value determined from quoted market prices. We record debt and equity securities classified as held-to-maturity at cost. On a specific identification basis, we report unrealized gains or losses from changes in fair value of certain available-for-sale debt and equity securities, net of tax, in equity as part of AOCL. We exclude unrealized gains or losses from earnings unless the related changes in fair value are determined to be other than temporary. We reflect unrealized gains or losses on our nuclear decommissioning investments as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our consolidated earnings or cash flows. We account for derivative instruments using SFAS No. 133. We report derivatives on our Consolidated Balance Sheets at their fair value. We record changes in fair value in AOCL if the derivative qualifies for cash flow hedge accounting; otherwise, we record the changes in earnings. For additional details regarding financial and derivative instruments, see Note 6, Financial and Derivative Instruments. GOODWILL: Goodwill is the excess of the purchase price over the fair value of the net assets of acquired companies. We test goodwill annually for impairment. There is no goodwill at the electric and gas utility segments. CMS-47 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The changes in the carrying amount of goodwill at the Enterprises segment for the years ended December 31, 2005 and 2006 are included in the following table:
IN MILLIONS ----------- Balance at January 1, 2005.......................................... $23 Currency translation adjustment................................... 4 --- Balance at December 31, 2005........................................ $27 Currency translation adjustment................................... (1) --- Balance at December 31, 2006........................................ $26 ===
IMPAIRMENT OF LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: We evaluate potential impairments of our long-lived assets, other than goodwill, based on various analyses, including the projection of undiscounted cash flows, whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the carrying amount of the investment or asset exceeds its estimated undiscounted future cash flows, we recognize an impairment loss and write-down the investment or asset to its estimated fair value. We also assess our ability to recover the carrying amounts of our equity method investments whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. This assessment requires us to determine the fair values of our equity method investments. We determine fair value using valuation methodologies, including discounted cash flows and the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. We record a write down if the fair value is less than the carrying value and the decline in value is considered to be other than temporary. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY: Our subsidiaries and affiliates whose functional currency is not the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect at the end of the fiscal period. We translate revenue and expense accounts of such subsidiaries and affiliates into U.S. dollars at the average exchange rates that prevailed during the period. We show these foreign currency translation adjustments in the stockholders' equity section on our Consolidated Balance Sheets. We include exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those that are hedged, in determining net income. At December 31, 2006, the cumulative Foreign Currency Translation component of stockholders' equity is $297 million, which primarily represents currency losses in Argentina and Brazil. The cumulative foreign currency loss due to the unfavorable exchange rate of the Argentine peso using an exchange rate of 3.073 pesos per U.S. dollar was $256 million, net of tax. The cumulative foreign currency loss due to the unfavorable exchange rate of the Brazilian real using an exchange rate of 2.136 reais per U.S. dollar was $45 million, net of tax. INVENTORY: We use the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities. We use the weighted average cost method for valuing materials and supplies inventory. We use the weighted average cost method for valuing coal inventory and classify these costs as generating plant fuel stock on our Consolidated Balance Sheets. MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property replacement to maintenance expense. We use the direct expense method to account for planned major maintenance activities. We charge planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and CMS-48 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) replacements. We depreciate utility property using straight-line rates approved by the MPSC. The composite depreciation rates for our properties are:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- Electric utility property..................................... 3.1% 3.1% 3.1% Gas utility property.......................................... 3.6% 3.6% 3.7% Other property................................................ 8.2% 7.6% 8.4%
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on the quantity of heat produced for electric generation. For nuclear fuel used after April 6, 1983, we charge certain disposal costs to nuclear fuel expense, recover these costs through electric rates, and remit them to the DOE quarterly. We elected to defer payment for disposal of spent nuclear fuel burned before April 7, 1983. Our DOE liability is $152 million at December 31, 2006 and $145 million at December 31, 2005. This amount includes interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. We have recovered, through electric rates, the amount of this liability, excluding a portion of interest. In conjunction with the sale of Palisades and the Big Rock ISFSI, we will retain this obligation and provide security to Entergy for this obligation in the form of cash, a letter of credit, or other acceptable means. For additional details on disposal of spent nuclear fuel, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Matters." OTHER INCOME AND OTHER EXPENSE: The following tables show the components of Other income and Other expense:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Other income Interest and dividends -- related parties.................... $ 9 $10 $ 6 Return on stranded and security costs........................ 5 6 9 Nitrogen oxide allowance sales............................... 8 2 -- Electric restructuring return................................ 4 6 6 Investment sale gain......................................... 1 -- 3 Reversal of contingent liability............................. -- 3 -- Refund of surety bond premium................................ 1 -- -- All other.................................................... 5 9 3 --- --- --- Total other income............................................. $33 $36 $27 === === ===
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Other expense Loss on SERP investment..................................... $ -- $ (2) $ (3) Loss on reacquired and extinguished debt.................... (5) (16) -- Civic and political expenditures............................ (2) (2) (2) Donations................................................... (9) -- (1) All other................................................... (3) (10) (9) ---- ---- ---- Total other expense........................................... $(19) $(30) $(15) ==== ==== ====
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at original cost when placed into service. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, we charge the original cost to accumulated depreciation, along with associated cost of removal, net of salvage. Cost of removal collected from our customers, but not spent, is recorded as a regulatory liability. We capitalize AFUDC on regulated major construction projects. We recognize gains or losses on the retirement or disposal of non-regulated assets in income. For additional details, see Note 8, Asset Retirement Obligations and Note 12, Property, Plant, and Equipment. CMS-49 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) RECLASSIFICATIONS: We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not affect consolidated net income (loss) for the years presented. RELATED PARTY TRANSACTIONS: We recorded income and expense from related parties as follows:
TYPE RELATED PARTY 2006 2005 2004 ---- ------------- ---- ---- ---- Income from our investments in Trust Preferred Securities related party trusts Companies...................... $ -- $ 1 $ 2 Interest expense on long-term Trust Preferred Securities debt Companies...................... (15) (29) (58)
TRADE RECEIVABLES: Accounts receivable is primarily composed of trade receivables and unbilled receivables. We record our accounts receivable at fair value. We establish an allowance for uncollectible accounts based on historical losses and management's assessment of existing economic conditions, customer trends, and other factors. We assess late payment fees on trade receivables based on contractual past-due terms established with customers. We charge accounts deemed uncollectible to operating expense. UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums, discounts, and expenses incurred in connection with the issuance of long-term debt and amortize those costs over the terms of the debt issues. We expense any refinancing costs as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and expenses and amortize them over the terms of the newly issued debt. UTILITY REGULATION: We account for the effects of regulation using SFAS No. 71. As a result, the actions of regulators affect when we recognize revenues, expenses, assets, and liabilities. We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets. We expect to recover these costs through rates over periods of up to 14 years. We recognized an OPEB transition obligation in accordance with SFAS No. 106 and established a regulatory asset for the amount that we expect to recover in rates over the next six years.
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Securitized costs (Note 4)...................................... $ 514 $ 560 Additional minimum pension liability (Note 7)(a)................ -- 399 Postretirement benefits (Note 7)(a)............................. 1,150 135 Customer Choice Act............................................. 190 222 Electric restructuring implementation plan...................... 40 74 Manufactured gas plant sites (Note 3)........................... 56 62 Abandoned Midland project....................................... 9 9 Unamortized debt costs.......................................... 86 93 Asset retirement obligations (Note 8)........................... 177 169 Stranded costs.................................................. 65 63 Other........................................................... 29 14 ------ ------ Total regulatory assets(b)...................................... $2,316 $1,800 ====== ====== Cost of removal (Note 8)........................................ $1,166 $1,120 Income taxes, net (Note 9)...................................... 539 455 Asset retirement obligations (Note 8)........................... 180 165 Other........................................................... 69 13 ------ ------ Total regulatory liabilities(b)................................. $1,954 $1,753 ====== ======
CMS-50 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) -------- (a) The change from 2005 to 2006 is largely due to the implementation of 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). For additional details, see Note 7, Retirement Benefits. (b) At December 31, 2006, we classified $19 million of regulatory assets as current regulatory assets and we classified $2.297 billion of regulatory assets as non-current regulatory assets. At December 31, 2005, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.781 billion of regulatory assets as non-current regulatory assets. At December 31, 2006 and December 31, 2005, all of our regulatory liabilities represented non-current regulatory liabilities. NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE: SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a revised definition of "fair value" and gives guidance on how to measure the fair value of assets and liabilities. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value in any new circumstances. However, additional disclosures will be required on the impact and reliability of fair value measurements reflected in our consolidated financial statements. The standard will also eliminate the existing prohibition of recognizing "day one" gains or losses on derivative instruments, and will generally require such gains and losses to be recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS No. 157. We currently do not hold any derivatives that would involve day one gains or losses. SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard will give us the option to select certain financial instruments and other items, which otherwise are not required to be measured at fair value, and measure those items at fair value. If we choose to elect the fair value option for an item, we would recognize unrealized gains and losses associated with changes in the fair value of the item over time. The statement will also require disclosures for items for which the fair value option has been elected. We are presently evaluating whether we will choose to elect the fair value option for any financial instruments or other items. FIN 48, Accounting for Uncertainties in Income Taxes: We discuss the requirements of this new accounting standard in Note 9, Income Taxes. 2: ASSET SALES, IMPAIRMENT CHARGES AND DISCONTINUED OPERATIONS ASSET SALES Gross cash proceeds received from the sale of assets, including discontinued operations, totaled $69 million in 2006, $61 million in 2005, and $219 million in 2004. For the year ended December 31, 2006, we sold the following assets:
DATE PRETAX AFTER-TAX SOLD BUSINESS/PROJECT GAIN GAIN ---- ---------------- ------ --------- IN MILLIONS October Land in Ludington, Michigan(a)......................... $ 2 $ 2 November MCV GP II(b)........................................... 77 38 --- --- Total gain on asset sales.............................. $79 $40 === ===
-------- (a) Sale of Ludington Land: We sold 36 parcels of land near Ludington, Michigan. Consumers held a majority share of the land, which Consumers co-owned with DTE Energy. Our portion of the gross proceeds was approximately $6 million. CMS-51 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (b) Sale of our Interest in the MCV Partnership and the MCV Facility: We sold 100 percent of our ownership interest of MCV GP II (the successor to CMS Midland, Inc.) and 100 percent of our ownership of the stock of CMS Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments for $60.5 million. These Consumers subsidiaries held our 49 percent interest in the MCV Partnership and our 35 percent lessor interest in the MCV Facility, held by the FMLP. The transaction is composed of non-real estate and real estate components. Since the carrying value of the MCV Facility, the real estate component of the transaction, exceeded the fair value, we recorded an impairment charge of $218 million. After considering tax effects and minority interest, the impairment charge reduced our consolidated net income by $80 million. Because of the MCV PPA, the transaction is a sale and leaseback for accounting purposes. SFAS No. 98 specifies the accounting required for a seller's sale and simultaneous leaseback involving real estate. We will have continuing involvement with the MCV Partnership through an existing guarantee associated with the future operations of the MCV Facility. As a result, we accounted for the MCV Facility, which is the asset subject to the leaseback, as a financing for accounting purposes and not a sale. We accounted for the non-real estate assets and liabilities associated with the transaction as a sale. As a financing, the MCV Facility remains on our Consolidated Balance Sheets and the related proceeds are recorded as a financing obligation. The value of the finance obligation is based on an allocation of the sale proceeds to the fair values of the net assets sold and fair value of the MCV Facility asset under the financing. The total proceeds of $57 million (net of $3 million of selling expenses) were less than the fair value of the net assets sold. As a result, there were no proceeds remaining to allocate to the MCV Facility and a finance obligation was not recorded. The previously described transaction resulted in an after-tax loss of $41 million. This loss includes the reversal of $30 million, into earnings, of certain cumulative amounts of the MCV Partnership derivative fair value changes that we accounted for in AOCL, the impairment charge on the MCV Facility, and gain on the sale of our interests in the MCV Partnership and the FMLP. For further information, see Note 6, Financial and Derivative Instruments, "Derivative Contracts Associated with the MCV Partnership." The following table summarizes the impacts of the transaction on net loss and stockholders' equity:
DESCRIPTION AFTER-TAX IMPACT ----------- ---------------- IN MILLIONS Asset impairment charges, net of minority interest of $95 million and $43 million in taxes........................................ $(80) General taxes, net of $1 million in taxes......................... 1 Gain on asset sales, net Reclassification of AOCL into earnings, net of $17 million in taxes........................................................ 30 Removal of interests in the MCV Partnership and the FMLP, net of $22 million in taxes......................................... 8 ---- Increase to consolidated net loss................................. $(41) Reclassification of AOCL into earnings, net of $17 million in taxes........................................................ (30) ---- Decrease to stockholders' equity.................................. $(71) ====
For the year ended December 31, 2005, we sold the following assets:
DATE PRETAX AFTER-TAX SOLD BUSINESS/PROJECT GAIN GAIN ---- ---------------- ------ --------- IN MILLIONS February GVK.................................................... $ 4 $ 3 April Scudder Latin American Power Fund...................... 2 1 April Gas turbine and auxiliary equipment.................... -- -- --- --- Total gain on asset sales.............................. $ 6 $ 4 === ===
CMS-52 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) For the year ended December 31, 2004, we sold the following assets:
DATE PRETAX AFTER-TAX SOLD BUSINESS/PROJECT GAIN GAIN ---- ---------------- ------ --------- IN MILLIONS February Bluewater Pipeline..................................... $ 1 $ 1 April Loy Yang............................................... -- -- May American Gas Index fund................................ 1 1 August Goldfields............................................. 45 29 December Moapa.................................................. 3 2 Various Other.................................................. 2 1 --- --- Total gain on asset sales.............................. $52 $34 === ===
PENDING ASSET SALES: In January 2007, we signed a binding letter of intent with Lucid Energy, LLC to sell a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets for $180 million. The assets being sold include all of our electric generating plant interests in Argentina and our interest in the TGM natural gas pipeline business in Argentina. We will maintain our interest in the TGN natural gas business in Argentina, which remains subject to a potential sale to the government of Argentina. We presently plan to retain our interest in TGN until such time as any interest or option held by the Argentine government expires. In Michigan, the sale includes the Antrim natural gas processing plant, 155 miles of associated gathering lines, and interests in three special purpose gas transmission pipelines that total 110 miles. We expect to close on the sale in the first half of 2007. In February 2007, we entered into an Agreement of Purchase and Sale with TAQA to sell our ownership interest in businesses in the Middle East, Africa, and India for $900 million. Businesses included in the sale are Taweelah, Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We expect to close on the sale in the middle of 2007. In February 2007, we signed a memorandum of understanding with Petroleos de Venezuela, S.A. to sell our ownership interest in SENECA and certain associated generating equipment for $106 million. We expect to close on the sale by March 31, 2007. We anticipate gross proceeds from these sale transactions to total approximately $1.186 billion. The book value of these assets at December 31, 2006 is approximately $913 million. The asset book values will vary between December 31, 2006 and each transaction's closing date. Final book value is dependent upon the timing of closing, results of operations for certain of the assets up to closing, and other factors. The cumulative currency translation losses at December 31, 2006 related to all of our businesses in Argentina are $256 million, net of tax. We also announced plans to conduct an auction to sell our Atacama combined gas pipeline and power generation businesses in Argentina and Chile, our electric generating plant in Jamaica, and our CPEE electric distribution business in Brazil. We expect to complete the sale of these businesses by the end of 2007. Takoradi and SENECA are consolidated subsidiaries that meet the criteria of held for sale under SFAS No. 144 subsequent to December 31, 2006. As a result, the major classes of assets and liabilities of Takoradi and SENECA CMS-53 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) will be classified as held for sale on our Consolidated Balance Sheets in 2007. The major classes of assets and liabilities of Takoradi and SENECA at December 31, 2006 are as follows:
DECEMBER 31 2006 ----------- ---- IN MILLIONS ASSETS Cash.............................................................. $ 35 Accounts receivable, net.......................................... 49 Notes receivable.................................................. 106 Property, plant and equipment, net................................ 52 Other............................................................. 12 ---- Total assets........................................................ $254 ==== LIABILITIES Accounts payable.................................................. $ 40 Minority interest................................................. 16 Other............................................................. 23 ---- Total liabilities................................................... $ 79 ====
Our pending asset sales are subject to the receipt of all necessary governmental, lender and partner approvals. We plan to use the proceeds from the pending asset sales to invest in our utility business and reduce parent company debt. ASSET IMPAIRMENT CHARGES The following table summarizes our asset impairments:
YEARS ENDED DECEMBER 31 PRETAX 2006 AFTER-TAX 2006 PRETAX 2005 AFTER-TAX 2005 PRETAX 2004 AFTER-TAX 2004 ----------------------- ----------- -------------- ----------- -------------- ----------- -------------- IN MILLIONS Asset impairments: Enterprises: MCV Partnership(a)..... $218 $ 80 $1,184 $385 $ -- $ -- GasAtacama(b).......... 239 169 -- -- -- -- Loy Yang(c)............ -- -- -- -- 125 81 GVK.................... -- -- -- -- 30 20 SLAP................... -- -- -- -- 5 3 Other.................. 2 1 -- -- -- -- ---- ---- ------ ---- ---- ---- Total asset impairments..... $459 $250 $1,184 $385 $160 $104 ==== ==== ====== ==== ==== ====
-------------- (a) As discussed in "Asset Sales," in November of 2006, we recorded an impairment charge of $218 million in our Consolidated Statements of Income (Loss). This impairment charge recognizes the reduction in fair value of the MCV Facility's real estate assets and results in an $80 million reduction to our consolidated net income after considering tax effects and minority interest. In the third quarter of 2005, NYMEX forward natural gas price forecasts for the years 2005 through 2010 increased substantially. Additionally, other independent natural gas long-term forward price forecasting organizations indicated their intention to raise their forecasts for the price of natural gas beyond 2010. As a result, the MCV Partnership determined an impairment analysis considering revised forward natural gas price assumptions was required. The MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows. The carrying value of the MCV Partnership's fixed assets exceeded the estimated fair value resulting in impairment charges of $1.159 billion to recognize the reduction in fair value of the MCV Facility's fixed assets and $25 million CMS-54 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) of interest capitalized during the construction of the MCV Facility. Our 2005 consolidated net income was reduced by $385 million, after considering tax effects and minority interest. (b) In 2004, the Argentine government authorized the restriction of exports of natural gas to Chile, giving priority to domestic demand in Argentina. This restriction had a harmful effect on GasAtacama's earnings since GasAtacama's gas-fired electric generating plant is located in Chile and uses Argentine gas for fuel. Bolivia agreed to export 4 million cubic meters of gas per day to Argentina. With the Bolivian gas supply, Argentina relaxed its export restrictions to GasAtacama. On May 1, 2006, the Bolivian government announced its intention to nationalize the natural gas industry and raise prices under its existing gas export contracts. Since May, gas flow from Bolivia has been restricted while Argentina and Bolivia renegotiated the price for gas. Simultaneously, gas supply to GasAtacama was restricted. In July 2006, Argentina agreed to increase the price it pays for gas from Bolivia through the term of the existing contract. Argentina also announced that it would recover all of this price increase by a special tax on its gas exports. The decision of Argentina to increase the cost of its gas exports, in addition to maintaining the gas restriction, increased the risk and cost of GasAtacama's fuel supply. In August 2006, a major gas supplier notified GasAtacama that it would no longer deliver gas to GasAtacama under the Argentine government's current policy. We performed an impairment analysis to determine the fair value of our investment in GasAtacama and concluded that the fair value of our investment, which includes notes receivable-related party from GasAtacama, was lower than the carrying amount and that this decline was other than temporary. In the third quarter of 2006, we recorded an impairment charge of $239 million in our Consolidated Statements of Income (Loss). As a result, our consolidated net income was reduced by $169 million after considering tax effects and minority interest. Our remaining investment in GasAtacama consists of $117 million of notes receivable, which includes a $49 million valuation allowance recognized due to the impairment. We report the notes under the Enterprises business segment and classify them as Notes receivable-related parties on our Consolidated Balance Sheets. Our proportionate share of earnings or losses at GasAtacama is first applied to the notes receivable valuation allowance. We apply all cash received on the notes, whether for principal or interest, to the principal of the notes. If we receive cash payments on the notes after the principal amount has been fully collected, we will record interest income. (c) In the first quarter of 2004, an impairment charge was recorded to recognize the reduction in fair value as a result of the sale of Loy Yang, completed in April 2004, which included a cumulative net foreign currency translation loss of approximately $110 million. DISCONTINUED OPERATIONS Our discontinued operations are a component of our Enterprises business segment. We reflect the following amounts in the Income (Loss) From Discontinued Operations line, in our Consolidated Statements of Income (Loss):
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Revenues....................................................... $-- $-- $11 === === === Discontinued operations: Pretax income from discontinued operations................... $ 8(a) $22(b) $14(c) Income tax expense........................................... 2 8 18 --- --- --- Income (Loss) From Discontinued Operations..................... $ 6 $14 $(4) === === ===
CMS-55 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) -------- (a) Adjustments include reductions of contingent tax liabilities primarily related to CMS Oil and Gas. (b) In December 2005, we received an arbitration award related to a discontinued operation of $13 million ($9 million after-tax). Additional adjustments include a reduction of a contingent liability and a settlement of a tax contingency primarily related to CMS Oil and Gas. (c) Includes a $15 million gain on disposal of discontinued operations primarily related to Parmelia. 3: CONTINGENCIES SEC AND DOJ INVESTIGATIONS: During the period of May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These so called round-trip trades had no impact on previously reported consolidated net income, earnings per share or cash flows, but had the effect of increasing operating revenues and operating expenses by equal amounts. CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies. Those two individuals filed a motion to dismiss the SEC action, which was denied. SECURITIES CLASS ACTION LAWSUITS: Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the United States District Court for the Eastern District of Michigan. The cases were consolidated into a single lawsuit (the "Shareholder Action"), which generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the court conditionally certified a class consisting of "all persons who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17, 2002 and who were damaged thereby." The court excluded purchasers of CMS Energy's 8.75 percent Adjustable Convertible Trust Securities ("ACTS") from the class and, in response, a new class action lawsuit was filed on behalf of ACTS purchasers (the "ACTS Action") against the same defendants named in the Shareholder Action. The settlement described in the following paragraph, if approved, will resolve both the Shareholder and ACTS Actions. On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the "MOU") dated December 28, 2006, subject to court approval, regarding settlement of the two class action lawsuits. The settlement was approved by a special committee of independent directors and by the full board of directors. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. The MOU is expected to lead to a detailed stipulation of settlement that will be presented to the assigned federal judge and the affected class in the first quarter of 2007. Under the terms of the MOU, the litigation will be settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy will make a payment of approximately $123 million plus an amount equivalent to interest on the outstanding unpaid settlement balance beginning on the date of preliminary approval of the court and running until the balance of the settlement funds is paid into a settlement account. Out of the total settlement, CMS Energy's insurers will pay approximately $77 million directly to the settlement account. CMS Energy took an approximately $123 million net CMS-56 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) pre-tax charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS Energy makes no admission of liability under the Shareholder Action and the ACTS Action. At December 31, 2006, we have recorded the $77 million as an accounts receivable and the $200 million as a legal settlement liability on our Consolidated Balance Sheets. GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified appropriate regulatory and governmental agencies that some employees at CMS MST and CMS Field Services appeared to have provided inaccurate information regarding natural gas trades to various energy industry publications, which compile and report index prices. CMS Energy is cooperating with an ongoing investigation by the DOJ regarding this matter. CMS Energy is unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation will have on its business. The CFTC filed a civil injunctive action against two former CMS Field Services employees in Oklahoma federal district court on February 1, 2005. The action alleges the two engaged in reporting false natural gas trade information, and seeks to enjoin such acts, compel compliance with the Commodities Exchange Act, and impose monetary penalties. A trial has been set for April 2007. CMS Energy is currently advancing legal defense costs to the two individuals in accordance with existing indemnification policies. BAY HARBOR: As part of the development of Bay Harbor by certain subsidiaries of CMS Energy, which went forward under an agreement with the MDEQ, third parties constructed a golf course and a park over several abandoned cement kiln dust (CKD) piles, left over from the former cement plant operation on the Bay Harbor site. Pursuant to the agreement with the MDEQ, a water collection system was constructed to recover seep water from one of the CKD piles and CMS Energy built a treatment plant to treat the seep water. In 2002, CMS Energy sold its interest in Bay Harbor, but retained its obligations under previous environmental indemnifications entered into at the inception of the project. In September 2004, the MDEQ issued a notice of noncompliance after finding high-pH seep water in Lake Michigan adjacent to the property. The MDEQ also found higher than acceptable levels of heavy metals, including mercury, in the seep water. In February 2005, the EPA executed an Administrative Order on Consent (AOC) to address problems at Bay Harbor, upon the consent of CMS Land Company (CMS Land) and CMS Capital, LLC, both subsidiaries of CMS Energy. Pursuant to the AOC, the EPA approved a Removal Action Work Plan in July 2005. Among other things, this plan calls for the installation of collection trenches to intercept high-pH CKD leachate flow to the lake. All collection systems contemplated in this work plan have been installed. Shoreline effectiveness monitoring is ongoing, and CMS Land is obligated to address any observed exceedances in pH. This may potentially include the augmentation of the collection system. In May 2006, the EPA approved a pilot carbon dioxide augmentation plan to augment the leachate recovery system by improving pH results in the Pine Court area of the collection system. The augmentation system was installed in June 2006. In February 2006, CMS Land submitted to the EPA a proposed Remedial Investigation and Feasibility Study for the East Park CKD pile. The EPA approved a schedule for near-term activities, which includes consolidating certain CKD materials and installing collection trenches in the East Park leachate release area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan and Final Engineering Design for Consolidation. CMS Energy and the MDEQ have initiated negotiations of an AOC and to define a long-term remedy at East Park. The owner of one parcel of land at Bay Harbor has filed a lawsuit in Emmet County Circuit Court against CMS Energy and several of its subsidiaries, as well as Bay Harbor Golf Club Inc., Bay Harbor Company LLC, David C. Johnson, and David V. Johnson, one of the developers at Bay Harbor. Several of these defendants have demanded indemnification from CMS Energy and affiliates for the claims made against them in the lawsuit. After a hearing in March 2006 on motions filed by CMS Energy and other defendants, the judge dismissed various counts of the complaint. CMS Energy will defend vigorously the existing case and any other property damage and personal injury claims or lawsuits. In November 2006, the judge ruled against a motion to dismiss the remaining counts, and the action is scheduled to go to trial in May 2007. CMS Land has entered into various access, purchase and settlement CMS-57 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) agreements with several of the affected landowners at Bay Harbor. CMS Land has purchased five unimproved lots and two lots with houses. At this time, CMS Land believes it has all necessary access arrangements to complete the remediation work required under the AOC. CMS Energy recorded charges related to this matter in 2004, 2005, and 2006 totaling $93 million, of which $9 million was recorded in 2006. At December 31, 2006, CMS Energy has a liability recorded of $52 million for its remaining obligations We based the liability on 2006 discounted costs, using a discount rate of 4.7 percent and an inflation rate of 1 percent on annual operating and maintenance costs. We used the interest rate for 30-year U.S. Treasury securities for the discount rate. The undiscounted amount of the remaining obligation is $65 million. We expect to pay $18 million in 2007, $17 million in 2008, $3 million in 2009, and the remaining expenditures as part of long-term operating and maintenance costs. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could impact our estimate of remedial action costs and the timing of the expenditures. An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy's financial condition and liquidity and could negatively impact CMS Energy's financial results. CMS Energy cannot predict the ultimate cost or outcome of this matter. CONSUMERS' ELECTRIC UTILITY CONTINGENCIES ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates. Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seeking permits to modify the plant from the EPA. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of "routine maintenance." If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric generating plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question. Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental Protection Act, we expect that we will ultimately incur investigation and remedial action costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies. We are a potentially responsible party at several contaminated sites administered under Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties with substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for the known Superfund sites will be between $1 million and $10 million. At December 31, 2006, we have recorded a liability for the minimum amount of our estimated probable Superfund liability. The timing of payments related to the remediation of our Superfund sites is uncertain. Any significant change in assumptions, such as different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs and the timing of our remediation payments. In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at Ludington. We removed and replaced part of the PCB material. Since proposing a plan to deal with the remaining materials, we have had several conversations with the EPA. The EPA has proposed a rule which would authorize continued use of such material in place, subject to certain restrictions. We are not able to predict when a final rule will be issued. LITIGATION: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. The judge deferred to the primary CMS-58 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The plaintiffs also filed suit in the United States Court for the Western District of Michigan, which the judge subsequently dismissed. The plaintiffs have appealed the dismissal to the United States Court of Appeals. We cannot predict the outcome of these appeals. CONSUMERS' ELECTRIC UTILITY RATE MATTERS ELECTRIC ROA: In prior orders, the MPSC approved recovery of Stranded Costs incurred from 2002 through 2003 plus the cost of money through the period of collection. At December 31, 2006, we had a regulatory asset for Stranded Costs of $65 million on our Consolidated Balance Sheets. We collect Stranded Costs through a surcharge on ROA customers. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers, which represent a decrease of 46 percent of ROA load compared to the end of December 2005. If downward ROA trends continue, it may extend the time it takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends and their effect on the timely recovery of Stranded Costs. POWER SUPPLY COSTS: To reduce the risk of high power supply costs during peak demand periods and to achieve our reserve margin target, we purchase electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2007 through 2010. As a result, we have an asset of $62 million for unexpired seasonal capacity and energy contracts at December 31, 2006. Capacity cost for these primarily seasonal electric capacity and energy contracts was $17 million in 2006. PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudency in annual plan and reconciliation proceedings. 2005 PSCR Reconciliation: In March 2006, we submitted our 2005 PSCR reconciliation filing to the MPSC. Our filing indicated that 2005 underrecoveries were $36 million for commercial and industrial customers. 2006 PSCR Plan: In August 2006, the MPSC issued an order approving our amended 2006 PSCR plan, which resulted in an increased PSCR factor for the remainder of 2006. PSCR underrecoveries for 2006 were $119 million. These underrecoveries are due to the MPSC delaying recovery of our increased METC costs and coal supply costs, increased bundled sales, and other cost increases beyond those included in the 2006 PSCR plan filings. PSCR 2007 Plan: In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as filed in our September 2006 case filing. The order also approved the incorporation of our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR monthly factor and allowed us to continue to roll in prior year under and overrecoveries into future PSCR plans. We expect to recover fully all of our PSCR costs. When we are unable to collect these costs as they are incurred, there is a negative impact on our cash flows from electric utility operations. We cannot predict the outcome of these proceedings. OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES THE MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35- year power purchase agreement beginning in 1990. We estimate that capacity and energy payments under the MCV PPA will be $620 million per year. The MCV PPA and the associated customer rates are unaffected by the November 2006 sale of our interest in the MCV Partnership. Underrecoveries related to the MCV PPA: The cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. We expensed underrecoveries of $57 million in 2006 and we estimate cash CMS-59 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) underrecoveries of $39 million in 2007. However, we use the direct savings from the RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy underrecoveries expense. RCP: In January 2005, we implemented the MPSC-approved RCP with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility based on natural gas market prices. This results in fuel cost savings for the MCV Facility, which the MCV Partnership shares with us. The RCP also requires us to contribute $5 million annually to a renewable resources program. As of December 2006, we have contributed $10 million to the renewable resources program. The underlying RCP agreement between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In January 2007, the Michigan Attorney General filed an appeal with the Michigan Supreme Court regarding the MPSC's order approving the RCP. We cannot predict the outcome of this matter. Regulatory Out Provision in the MCV PPA: After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The MCV Partnership has notified us that it takes issue with our intended exercise of the regulatory out provision. We believe that the provision is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out provision, the MCV Partnership has the right to terminate the MCV PPA, which could affect our reserve margin. We anticipate that the MPSC will review our exercise of the regulatory out provision and the likely consequences of such action in 2007. It is possible that in the event that the MCV Partnership ceases performance under the MCV PPA, prior orders could limit recovery of replacement power costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the cost of replacement power, this could result in our costs exceeding the recovery amount allowed by the MPSC. We cannot predict the outcome these matters. THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT: In July 2006, we reached an agreement to sell Palisades to Entergy for $380 million and pay Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. Palisades Asset Sale: The sale is subject to various regulatory approvals, including the MPSC's approval of the power purchase agreement, and the NRC's approval of the transfer of the operating license to Entergy and other related matters. In February 2007, the FERC issued an order approving the sale of power to us under the power purchase agreement and granted other related approvals, with what we believe are minor exceptions and conditions that we believe can be adequately accepted. In October 2006, the Federal Trade Commission issued a notice that neither it nor the DOJ's Antitrust Division plans to take enforcement action on the sale. The final purchase price will be subject to various closing adjustments such as working capital and capital expenditure adjustments, adjustments for nuclear fuel usage and inventory, and the date of closing. However, termination of the sale agreement can occur if the closing does not take place by January 2008. To accommodate delays in receiving regulatory approval, extension of the closing can occur for up to six months. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur. Under the agreement, if the transaction does not close by March 1, 2007, a reduction in the purchase price occurs of approximately $80,000 per day, with additional costs if the deal does not close by June 1, 2007. Based on the MPSC's published schedule for the contested case proceedings regarding this transaction, we target to close on the transaction in the second quarter of 2007. Based on the anticipated closing date, this delay would result in a purchase price reduction for Palisades of approximately $5 million. We estimate that the Palisades sale will result in a $31 million premium above the Palisades asset value at the anticipated closing date after accounting for estimated sales-related costs. We expect that this premium will benefit our customers. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur. CMS-60 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) We have notified the NMC that we plan to terminate the NMC's operation of Palisades, if the sale is completed, which would require us to pay the NMC an estimated $12 million. Due to the regulatory approvals pending, we have not recorded this contingent obligation. Palisades Power Purchase Agreement: As part of the transaction, Entergy will sell us 100 percent of the plant's output up to its current capacity of 798 MW under a 15-year power purchase agreement. During the term of the power purchase agreement, Entergy is obligated to supply, and we are obligated to take, all capacity and energy from the Palisades plant, exclusive of uprates above the plant's presently specified capacity. When the plant is not operating or is derated, under certain circumstances Entergy can elect to provide replacement power from another source at the rates set in the power purchase agreement. Otherwise, we would have to obtain replacement power from the market. However, we are only obligated to pay Entergy for capacity and energy actually delivered by Entergy either from the plant or from an allowable replacement source chosen by Entergy. If Entergy schedules a plant outage in June, July or August, Entergy is required to provide replacement power at power purchase agreement rates. There are significant penalties incurred by Entergy if the delivered energy fails to achieve a minimum capacity factor level during July and August. Over the term of the power purchase agreement, the pricing terms are such that Consumers' ratepayers will retain the benefits of the Palisades plant's low-cost nuclear generation. Because of the power purchase agreement that will be in place between Consumers and Entergy, the transaction is effectively a sale and leaseback for accounting purposes. SFAS No. 98 specifies the accounting required for a seller's sale and simultaneous leaseback transaction involving real estate, including real estate with equipment. Due to forms of continuing involvement, we will account for the transaction as a financing for accounting purposes and not a sale. As such, we have not classified the assets as held for sale on our Consolidated Balance Sheets. NUCLEAR PLANT DECOMMISSIONING: The MPSC and the FERC regulate the recovery of costs to decommission, or remove from service, our Big Rock and Palisades nuclear plants. Decommissioning funding practices approved by the MPSC require us to file a report on the adequacy of funds for decommissioning at three-year intervals. We prepared and filed updated cost estimates for Big Rock and Palisades in March 2004. Excluding additional costs for spent nuclear fuel storage due to the DOE's failure to accept this spent nuclear fuel on schedule, these reports show a decommissioning cost of $361 million for Big Rock and $868 million for Palisades. Big Rock's estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. Updated cost projections for Big Rock indicate an anticipated decommissioning cost of $390 million as of December 2006. Big Rock: In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. In our March 2004 report to the MPSC, we indicated that we would manage the decommissioning trust fund to meet annual NRC financial assurance requirements by withdrawing NRC radiological decommissioning costs from the fund and initially funding non-NRC greenfield costs out of corporate funds. In March 2006, we contributed $16 million to the trust fund from our corporate funds to support NRC radiological decommissioning costs. Excluding the additional nuclear fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we are projecting that the level of funds provided by the trust will fall short of the amount needed to complete the decommissioning by an additional $37 million. This total of $53 million, which are costs associated with NRC radiological and non-NRC greenfield decommissioning work, are being funded out of corporate funds. We plan to seek recovery of such expenditures recorded on our consolidated balance sheets in future filings with the MPSC. We have incurred Big Rock expenditures, excluding nuclear fuel storage costs, of $41 million for the year ended December 31, 2006, and cumulative expenditures through December 31, 2006 of $386 million. These activities had no material impact on consolidated net income. At December 31, 2006, we have an investment in nuclear decommissioning corporate funded trust funds of $4 million for Big Rock. In addition, at December 31, 2006, we have charged $10 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock. CMS-61 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Palisades: Excluding additional nuclear fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we concluded, based on the cost estimates filed in March 2004, that the existing Palisades' surcharge of $6 million needed to be increased to $25 million annually, beginning January 2006. A settlement agreement was approved by the MPSC, providing for the continuation of the existing $6 million annual decommissioning surcharge through 2011, which was our original license expiration date, and for the next periodic review to be filed in March 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability. At December 31, 2006, we have an investment in the MPSC nuclear decommissioning trust funds of $587 million for Palisades. In addition, at December 31, 2006, we have a FERC decommissioning trust fund with a balance of $11 million. In the FERC's February 2007 order regarding the Palisades sale, the FERC granted our request to apply the $11 million FERC decommissioning trust fund balance toward the Big Rock decommissioning shortfall, subject to the outcome of the NRC operating license transfer proceedings and completion of the Palisades sale transaction. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 8, Asset Retirement Obligations. In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. In January 2007, the NRC renewed the Palisades operating license for 20 years, extending it to 2031. At this time, we cannot determine what impact this will have on decommissioning costs or the adequacy of funding. Initial estimates of decommissioning costs, assuming a plant retirement date of 2031, show decommissioning costs of either $818 million or $1.049 billion for Palisades, depending on the decommissioning methodology assumed. These costs, which exclude additional costs for spent nuclear fuel storage due to the DOE's failure to accept spent nuclear fuel on schedule, are given in 2003 dollars. NUCLEAR MATTERS DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other utilities participated, has not been successful in producing more specific relief for the DOE's failure to accept the spent nuclear fuel. There are two court decisions that support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. Over 60 utilities have initiated litigation in the United States Court of Claims. We filed our complaint in December 2002. If our litigation against the DOE is successful, we plan to use any recoveries as reimbursement for the incurred costs of spent nuclear fuel storage. We can make no assurance that the litigation against the DOE will be successful. In 2002, the site at Yucca Mountain, Nevada was designated for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE, in due course, will submit a final license application to the NRC for the repository. The application and review process is estimated to take several years. Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $30 million in any policy year if insured losses in excess of NEIL's maximum policyholders surplus occur at our, or any other member's, nuclear facility. NEIL's policies include coverage for acts of terrorism. At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear energy hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. Part of the Price-Anderson Act's financial protection is a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed if a nuclear incident CMS-62 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) occurs at any nuclear generating facility. The maximum assessment against us could be $101 million per occurrence, limited to maximum annual installment payments of $15 million. We also maintain insurance under a program that covers tort claims for bodily injury to nuclear workers caused by nuclear hazards. The policy contains a $300 million nuclear industry aggregate limit. Under a previous insurance program providing coverage for claims brought by nuclear workers, we remain responsible for a maximum assessment of up to $6 million. This requirement will end December 31, 2007. Big Rock remains insured for nuclear liability up to $544 million through nuclear insurance and NRC indemnity, and maintains a nuclear property insurance policy from NEIL. Insurance policy terms, limits, and conditions are subject to change during the year as we renew our policies. CONSUMERS' GAS UTILITY CONTINGENCIES GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remediation costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through proceeds derived from a settlement with insurers and MPSC-approved rates. At December 31, 2006, we have a liability of $24 million, net of $59 million of expenditures incurred to date, and a regulatory asset of $56 million. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs and the timing our remediation payments. CONSUMERS' GAS UTILITY RATE MATTERS GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudency in annual plan and reconciliation proceedings. The following table summarizes our GCR reconciliation filings with the MPSC:
GAS COST RECOVERY RECONCILIATION -------------------------------------------------------------------------------------------------- NET OVER- GCR COST GCR YEAR DATE FILED ORDER DATE RECOVERY OF GAS SOLD DESCRIPTION OF NET OVERRECOVERY -------- ---------- ---------- ---------- ------------ --------------------------------- 2004-2005 June 2005 April 2006 $2 million $1.4 billion The net overrecovery includes interest expense through March 2005 and refunds that we received from our suppliers that are required to be refunded to our customers. 2005-2006 June 2006 Pending $3 million $1.8 billion The net overrecovery includes $1 million interest income through March 2006, which resulted from a net underrecovery position during the majority of the GCR period.
GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan year, which resulted in approval of a settlement agreement and established a fixed price cap of $10.10 per mcf for the December 2005 through March 2006 billing period. We were able to maintain our billing GCR factor below the CMS-63 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) authorized level for that period. The order was appealed to the Michigan Court of Appeals by one intervenor. We are unable to predict the outcome of this proceeding. GCR plan for year 2006-2007: In December 2005, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2006 through March 2007. Our request proposed using a GCR factor consisting of: - a base GCR ceiling factor of $11.10 per mcf, plus - a quarterly GCR ceiling price adjustment contingent upon future events. In July 2006, all parties signed a partial settlement agreement, which calls for a base GCR ceiling factor of $9.48 per mcf. The settlement agreement base GCR ceiling factor is subject to a quarterly GCR ceiling price adjustment mechanism. The adjustment mechanism allows an adjustment of the base ceiling factor to reflect a portion of cost increases, if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. The MPSC approved the settlement agreement in August 2006. The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor for the month of February 2007 is $7.63 per mcf. GCR plan for year 2007-2008: In December 2006, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2007 through March 2008. Our request proposed using a GCR factor consisting of: - a base GCR ceiling factor of $8.47 per mcf, plus - a quarterly GCR ceiling price adjustment contingent upon future events. 2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC for an annual gas rate increase of $132 million. In May 2006, the MPSC issued an order granting us interim rate relief of $18 million annually. In November 2006, the MPSC issued an order granting rate relief of $81 million, which included the $18 million of interim relief granted in May 2006. The MPSC authorized an 11 percent return on common equity, a reduction from our then current 11.4 percent authorized rate of return. In addition, the order made permanent the collection of a $58 million surcharge granted in October 2004. 2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC for an annual gas rate increase of $88 million and an 11.25 percent authorized return on equity. We have proposed the use of a Revenue Decoupling and Conservation Incentive Mechanism for residential and general service rate classes to help assure a reasonable opportunity to recover costs that do not fluctuate with volumetric changes. OTHER CONTINGENCIES GAS INDEX PRICE REPORTING LITIGATION: CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a result of claimed inaccurate natural gas price reporting. Allegations include manipulation of NYMEX natural gas futures and options prices, price-fixing conspiracies, and artificial inflation of natural gas retail prices in California, Colorado, Kansas, Missouri, Tennessee, and Wyoming. In September 2006, CMS MST reached an agreement in principle to settle the master class action suit in California for $7 million. The settlement agreement has been signed. The settlement payment is not due until the court has approved the settlement. CMS Energy deemed this settlement to be probable and accrued the payment in its consolidated financial statements at September 30, 2006. CMS Energy and the other CMS Energy defendants will defend themselves vigorously against all of these matters but cannot predict their outcome. DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD), the primary construction contractor for the DIG facility, presented DIG with a change order to their construction contract and filed an action CMS-64 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) in Michigan state court against DIG, claiming contractual damages in the amount of $110 million, plus interest and costs. DFD also filed a construction lien for the $110 million. DIG contested both of the claims made by DFD. In addition to drawing down on three letters of credit totaling $30 million that it obtained from DFD, DIG filed an arbitration claim against DFD asserting in excess of an additional $75 million in claims against DFD. The judge in the Michigan state court case entered an order staying DFD's prosecution of its claims in the court case and permitting the arbitration to proceed. The arbitration hearing concluded on September 28, 2006 and the arbitration panel issued its award on December 21, 2006. The arbitration panel awarded DIG approximately $25 million, including interest, on its various claims against DFD presented in the arbitration. The panel also awarded DFD approximately $5 million on its claims and credited DFD approximately $30 million for the three letters of credit DIG drew against DFD, plus $2 million in interest on the award amount. This resulted in a net amount due DFD, inclusive of interest, in the amount of approximately $12 million, which DIG has paid. CMS Energy had previously accrued a liability of approximately $30 million relating to the three letters of credit. In December 2006, we recorded $20 million pre-tax as a reduction of Operating Expenses in our Consolidated Statements of Income (Loss). The arbitration between DIG and DFD is now complete. FORMER CMS OIL AND GAS OPERATIONS: A Michigan trial judge granted Star Energy, Inc. and White Pine Enterprises, LLC a declaratory judgment in an action filed in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas subsidiary, violated an oil and gas lease and other arrangements by failing to drill wells it had committed to drill. A jury then awarded the plaintiffs a $7.6 million award. Appeals were filed of the original verdict and a subsequent decision of the court on remand. The court of appeals issued an opinion on May 26, 2005 remanding the case to the trial court for a new trial on damages. At a status conference on April 10, 2006, the judge set a six-month discovery period. The case is set for a new trial on damages in August 2007. The parties attended a court-ordered mediation on July 14, 2006 and the matter was not resolved. Enterprises has an indemnity obligation with regard to losses to Terra that might result from this litigation. CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase agreement, CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery in La Plata, Argentina. As a result of the so-called "Emergency Laws," payments by YPF Repsol under the power purchase agreement have been converted to pesos at the exchange rate of one U.S. dollar to one Argentine peso. Such payments are currently insufficient to cover CMS Ensenada's operating costs. The Argentine commercial court granted injunctive relief to CMS Ensenada pursuant to an ex parte action, and such relief remained in effect until completion of arbitration on the matter, administered by the International Chamber of Commerce (ICC). The arbitration hearing was held in July 2005. The ICC released the arbitral tribunal's partial award dated August 22, 2006. The partial award is generally favorable to CMS Ensenada. Following the arbitation decision, CMS Ensenada reached agreement with YPF Repsol, under which YPF Repsol paid approximately $24 million for the period through December 31, 2006, and the parties agreed to revert substantially to the terms and conditions of the original contract. We recorded $21 million as Operating Revenue and $3 million as Other interest in our Consolidated Statements of Income (Loss). The parties have notified the ICC that all outstanding issues relating to the arbitral tribunal's partial award have been resolved fully by mutual agreement between the parties. ARGENTINA: As part of its energy privatization incentives, Argentina directed CMS Gas Transmission to calculate tariffs in U.S. dollars, then convert them to pesos at the prevailing exchange rate, and to adjust tariffs every six months to reflect changes in inflation. Starting in early 2000, Argentina suspended the inflation adjustments. In January 2002, the Republic of Argentina enacted the Public Emergency and Foreign Exchange System Reform Act. This law repealed the fixed exchange rate of one U.S. dollar to one Argentine peso, converted all dollar-denominated utility tariffs and energy contract obligations into pesos at the same one-to-one exchange rate, and directed the Government of Argentina to renegotiate such tariffs. CMS-65 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) CMS Gas Transmission began arbitration proceedings against the Republic of Argentina (Argentina) under the auspices of the International Centre for the Settlement of Investment Disputes (ICSID) in mid-2001, citing breaches by Argentina of the Argentine-U.S. Bilateral Investment Treaty (BIT). In May 2005, an ICSID tribunal concluded, among other things, that Argentina's economic emergency did not excuse Argentina from liability for violations of the BIT. The ICSID tribunal found in favor of CMS Gas Transmission, and awarded damages of U.S. $133 million, plus interest. The ICSID Convention provides that either party may seek annulment of the award based upon five possible grounds specified in the Convention. Argentina's Application for Annulment was formally registered by ICSID on September 27, 2005 and will be considered by a newly constituted panel. On December 28, 2005, certain insurance underwriters paid the sum of $75 million to CMS Gas Transmission in respect of their insurance obligations resulting from non-payment of the ICSID award. The payment, plus interest, is subject to repayment by CMS Gas Transmission in the event that the ICSID award is annulled. Pending the outcome of the annulment proceedings, CMS Energy has recorded the $75 million payment as a long-term deferred credit. QUICKSILVER RESOURCES, INC.: Quicksilver sued CMS MST for breach of contract in connection with a Contract for Sale and Purchase of natural gas, pursuant to which Quicksilver agreed to sell, and CMS MST to buy, natural gas, Quicksilver believes that it is entitled to more payments for natural gas than it has received. CMS MST disagrees with Quicksilver's analysis and believes that it has paid all amounts owed for delivery of gas pursuant to the contract. Quicksilver is seeking damages of up to approximately $126 million, plus prejudgement interest and attorney fees, which in our judgement is totally unsupported by the facts. T.E.S. FILER CITY AIR PERMIT ISSUE: In January 2007, we received a Notice of Violation (NOV) from the EPA alleging that T.E.S. Filer City, a generating facility in which we have a 50 percent partnership interest, exceeded certain air permit limits. We are in discussions with the EPA with regard to these allegations, but cannot predict the financial impact or outcome of this issue. OTHER: In addition to the matters disclosed within this Note, Consumers and certain other subsidiaries of CMS Energy are parties to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters. We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or future results of operations. FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: The Interpretation requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee. CMS-66 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table describes our guarantees at December 31, 2006:
MAXIMUM CARRYING GUARANTEE DESCRIPTION ISSUE DATE EXPIRATION DATE OBLIGATION AMOUNT --------------------- ------------ ------------------------ ---------- -------- (IN MILLIONS) Indemnifications from asset sales and other agreements(a) October 1995 Indefinite $1,133 $ 1 Standby letters of credit and loans(b) Various Various through May 2010 85 -- Surety bonds and other indemnifications Various Indefinite 10 -- Guarantees and put options(c) Various Various through 209 1 September 2027 Nuclear insurance retrospective premiums Various Indefinite 137 --
-------------- (a) The majority of this amount arises from routine provisions in stock and asset sales agreements under which we indemnify the purchaser for losses resulting from events such as claims resulting from tax disputes and the failure of title to the assets or stock sold by us to the purchaser. We believe the likelihood of a loss for any remaining indemnifications to be remote. (b) Standby letters of credit include letters of credit issued under an amended credit agreement with Citicorp USA, Inc. The amended credit agreement is supported by a guaranty issued by certain subsidiaries of CMS Energy. At December 31, 2006, letters of credit issued on behalf of unconsolidated affiliates totaling $65 million were outstanding. (c) Maximum obligation includes $85 million related to the MCV Partnership's non-performance under a steam and electric power agreement with Dow. We sold our interests in the MCV Partnership and the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments, to pay $85 million, subject to certain reimbursement rights, if Dow terminates an agreement under which the MCV Partnership provides it steam and electric power. This agreement expires in March 2016, subject to certain terms and conditions. The purchaser secured their reimbursement obligation with an irrevocable letter of credit of up to $85 million. CMS-67 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table provides additional information regarding our guarantees:
EVENTS THAT WOULD HOW GUARANTEE REQUIRE GUARANTEE DESCRIPTION AROSE PERFORMANCE --------------------- ------------- ----------------- Indemnifications from asset sales and Stock and asset Findings of other sales misrepresenta- agreements agreements tion, breach of warranties, and other specific events or circumstances Standby letters of credit Credit agreement Non-payment by and loans CMS Energy and Enterprises of obligations under the credit agreement Surety bonds and other Normal operating Nonperformance indemnifications activity, permits and licenses Guarantees and put options Normal operating Nonperformance or activity non-payment by a Agreement to subsidiary under provide power and a related steam to Dow Bay contract MCV Harbor Partnership's remediation nonperformance or efforts non-payment under a related contract Owners exercising put options requiring us to purchase property Nuclear insurance retrospective Normal operations Call by NEIL and premiums of nuclear plants Price-Anderson Act for nuclear incident
At December 31, 2006, certain contracts contained provisions allowing us to recover, from third parties, amounts paid under the guarantees. For example, if we are required to purchase a property under a put option agreement, we may sell the property to recover the amount paid under the option. We enter into various agreements containing tax and other indemnification provisions in connection with a variety of transactions, including the sale of our interests in the MCV Partnership and the FMLP. While we are unable to estimate the maximum potential obligation related to these indemnities, we consider the likelihood that we would be required to perform or incur significant losses related to these indemnities and the guarantees listed in the preceding tables to be remote. Project Financing: We enter into various project-financing security arrangements such as equity pledge agreements and share mortgage agreements to provide financial or performance assurance to third parties on behalf of certain unconsolidated affiliates. Expiration dates for these agreements vary from March 2015 to June 2020 or terminate upon payment or cancellation of the obligation. Non-payment or other act of default by an unconsolidated affiliate would trigger enforcement of the security. If we were required to perform under these agreements, the maximum amount of our obligation under these agreements would be equal to the value of the shares relinquished to the guaranteed party at the time of default. In February 2007, we reached an agreement to sell our ownership interests in businesses in the Middle East, Africa, and India to TAQA. The proposed agreement calls for TAQA to either arrange for substitute guarantee agreements to replace our contingent obligations related to our project-financing security agreements or assume all of our contingent obligations under such agreements. In the event beneficiaries under these agreements refuse to accept substitution or assumption of our contingent obligations, TAQA will indemnify us for any losses under our project-financing security agreements that relate to events occurring after the close of the sale. For more details on the sale of our ownership interests to TAQA, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. CMS-68 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 4: FINANCINGS AND CAPITALIZATION
LONG-TERM DEBT AT DECEMBER 31 FOLLOWS: INTEREST RATE (%) MATURITY 2006 2005 -------------------------------------- ----------------- -------- ---- ---- (IN MILLIONS) CMS ENERGY CORPORATION Senior notes.............................. 9.875 2007 $ 289 $ 365 8.900 2008 260 260 7.500 2009 409 409 7.750 2010 300 300 8.500 2011 300 300 6.300 2012 150 150 6.875 2015 125 125 3.375(a) 2023 150 150 2.875(a) 2024 288 288 ------ ------ 2,271 2,347 Other..................................... 1 2 ------ ------ Total -- CMS Energy Corporation........ 2,272 2,349 ------ ------ CONSUMERS ENERGY COMPANY First mortgage bonds...................... 4.250 2008 250 250 4.800 2009 200 200 4.400 2009 150 150 4.000 2010 250 250 5.000 2012 300 300 5.375 2013 375 375 6.000 2014 200 200 5.000 2015 225 225 5.500 2016 350 350 5.150 2017 250 250 5.650 2020 300 300 5.650 2035 147 150 5.800 2035 175 175 ------ ------ 3,172 3,175 ------ ------ Senior notes.............................. 6.375 2008 159 159 6.875 2018 180 180 ------ ------ 339 339 ------ ------ Securitization bonds...................... 5.384(b) 2007-2015 340 369 FMLP debt................................. -- 207 Nuclear fuel disposal liability........... (c) 152 145 Tax-exempt pollution control revenue bonds.................................. Various 2010-2035 161 161 ------ ------ Total -- Consumers Energy Company...... 4,164 4,396 ------ ------ OTHER SUBSIDIARIES.......................... 331 363 ------ ------ Total principal amount outstanding 6,767 7,108 Current amounts........................... (551) (289) Net unamortized discount.................. (14) (19) ------ ------ Total long-term debt........................ $6,202 $6,800 ====== ======
-------------- (a) Contingently convertible notes. See "Contingently Convertible Securities" section within this Note for further discussion of the conversion features. (b) Represents the weighted average interest rate at December 31, 2006 (5.295 percent at December 31, 2005). (c) Maturity date uncertain. CMS-69 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) RETIREMENTS: The following is a summary of significant long-term debt retirements during 2006:
PRINCIPAL (IN MILLIONS) INTEREST RATE (%) RETIREMENT DATE MATURITY DATE ------------- ----------------- --------------- ------------- CMS ENERGY Senior notes................... $ 76 9.875 January through October 2007 April 2006 CONSUMERS Long-term debt -- related parties..................... 129 9.00 February 2006 June 2031 FMLP debt...................... 56 13.25 July 2006 July 2006 FMLP debt(a)................... 151 Various November 2006 July 2009 ENTERPRISES CMS Generation Investment Co. IV Bank Loan................ 49 Variable June through December 2008 December 2006 ---- Total....................... $461 ====
-------------- (a) FMLP debt of $151 million was removed as part of the November 2006 transaction in which Consumers sold its interest in the FMLP. FIRST MORTGAGE BONDS: Consumers secures its FMB by a mortgage and lien on substantially all of its property. Its ability to issue FMB is restricted by certain provisions in the first mortgage bond indenture and the need for regulatory approvals under federal law. Restrictive new issuance provisions in the first mortgage bond indenture include achieving a two-times interest coverage ratio and having sufficient unfunded net property additions. SECURITIZATION BONDS: Certain regulatory assets collateralize Securitization bonds. The bondholders have no recourse to our other assets. Through Consumers' rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses on the Securitization bonds. Securitization surcharges collected are remitted to a trustee for the Securitization bonds and are not available to creditors of Consumers or its affiliates. Securitization surcharges totaled $50 million in 2006 and 2005. LONG-TERM DEBT -- RELATED PARTIES: CMS Energy and Consumers each formed various statutory wholly-owned business trusts for the sole purpose of issuing preferred securities and lending the gross proceeds to themselves. The sole assets of the trusts consist of the debentures described in the following table. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trusts issued. We determined that we do not hold the controlling financial interest in our trust preferred security structures. Accordingly, those entities are reflected in Long-term debt -- related parties. The following is a summary of Long-term debt -- related parties at December 31:
DEBENTURE AND RELATED PARTY INTEREST RATE (%) MATURITY 2006 2005 --------------------------- ----------------- -------- ---- ---- (IN MILLIONS) Convertible subordinated debentures, CMS Energy Trust I....................................... 7.75 2027 $178 $ 178 Subordinated debentures: Consumers Energy Company Financing IV......... 9.00 -- 129 ---- ----- Total principal amounts outstanding............. 178 307 Current amounts............................... -- (129) ---- ----- Total Long-term debt -- related parties......... $178 $ 178 ==== =====
In the event of default, holders of the Trust Preferred Securities would be entitled to exercise and enforce the trusts' creditor rights against us, which may include acceleration of the principal amount due on the debentures. CMS Energy and Consumers, as applicable, have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debentures, related CMS-70 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) indenture and trust documents, provide full and unconditional guarantees for the trusts' obligations under the preferred securities. DEBT MATURITIES: At December 31, 2006, the aggregate annual contractual maturities for long-term debt and long-term debt -- related parties for the next five years are:
PAYMENTS DUE -------------------------------- 2007 2008 2009 2010 2011 ---- ---- ---- ---- ---- (IN MILLIONS) Long-term debt and long-term debt -- related parties.......................................... $401 $837 $814 $660 $353
REGULATORY AUTHORIZATION FOR FINANCINGS: In May 2006, the FERC issued an order authorizing Consumers to issue up to $2.0 billion of secured and unsecured short-term securities for the following purposes: - up to $1.0 billion for general corporate purposes, and - up to $1.0 billion of FMB or other securities to be issued solely as collateral for other short-term securities. Also in May 2006, the FERC issued an order authorizing Consumers to issue up to $5.0 billion of secured and unsecured long-term securities for the following purposes: - up to $1.5 billion for general corporate purposes, - up to $1.0 billion for purposes of refinancing or refunding existing long-term debt, and - up to $2.5 billion of FMB or other securities to be issued solely as collateral for other long-term securities. The authorizations are for a two-year period beginning July 1, 2006 and ending June 30, 2008. Any long-term issuances during the two-year authorization period are exempt from the FERC's competitive bidding and negotiated placement requirements. REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities with banks are available at December 31, 2006:
OUTSTANDING AMOUNT OF AMOUNT LETTERS-OF- AMOUNT COMPANY EXPIRATION DATE FACILITY BORROWED CREDIT AVAILABLE ------- --------------- --------- -------- ----------- --------- (IN MILLIONS) CMS Energy........................ May 18, 2010 $300 $-- $98 $202 Consumers......................... March 30, 2007 300 -- -- 300 Consumers......................... May 18, 2010 500 -- 58 442
Effective February 2007, Consumers terminated their $300 million facility. DIVIDEND RESTRICTIONS: CMS Energy's $300 million secured revolving credit facility restricts payments of dividends on our common stock during a 12-month period to $150 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility. Under the provisions of its articles of incorporation, at December 31, 2006, Consumers had $215 million of unrestricted retained earnings available to pay common stock dividends. Covenants in Consumers' debt facilities restrict its ability to pay dividends to us by capping common stock dividend payments at $300 million in a calendar year. At December 31, 2006, $2.702 billion of net assets were subject to such restrictions. Provisions of the Federal Power Act and the Natural Gas Act effectively restrict dividends to the amount of Consumers' retained earnings. During 2006, we received $147 million of common stock dividends from Consumers. SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, Consumers sells certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. The special purpose entity CMS-71 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) sold $325 million of receivables at December 31, 2006 and December 31, 2005. Consumers continues to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against Consumers' other assets for failure of a debtor to pay when due and no right to any receivables not sold. Consumers has neither recorded a gain or loss on the receivables sold nor retained interest in the receivables sold. Certain cash flows under Consumers' accounts receivable sales program are shown in the following table:
YEARS ENDED DECEMBER 31 2006 2005 ----------------------- ---- ---- (IN MILLIONS) Net cash flow as a result of accounts receivable financing...... $ -- $ 21 Collections from customers...................................... $5,684 $4,859
CAPITALIZATION: The authorized capital stock of CMS Energy consists of: - 350 million shares of CMS Energy Common Stock, par value $0.01 per share, and - 10 million shares of CMS Energy Preferred Stock, par value $0.01 per share. PREFERRED STOCK: Our Preferred Stock outstanding follows:
NUMBER OF SHARES --------------------- DECEMBER 31 2006 2005 2006 2005 ----------- ---- ---- ---- ---- (IN MILLIONS) Preferred Stock 4.50% convertible, Authorized 10,000,000 shares(a).............. 5,000,000 5,000,000 $250 $250 Preferred subsidiary interest................... 11 11 ---- ---- Total Preferred stock............................. $261 $261 ==== ====
-------------- (a) See the "Contingently Convertible Securities" section within this Note for further discussion of the convertible preferred stock. PREFERRED STOCK OF SUBSIDIARY: Consumers' Preferred Stock outstanding follows:
OPTIONAL NUMBER OF SHARES REDEMPTION ----------------- DECEMBER 31 SERIES PRICE 2006 2005 2006 2005 ----------- ------ ---------- ---- ---- ---- ---- (IN MILLIONS) Preferred Stock Cumulative $100 par value, Authorized 7,500,000 shares, with no mandatory redemption.............. $4.16 $103.25 68,451 68,451 $ 7 $ 7 $4.50 $110.00 373,148 373,148 37 37 --- --- Total Preferred stock of subsidiary.... $44 $44 === ===
CONTINGENTLY CONVERTIBLE SECURITIES: At December 31, 2006, the significant terms of our contingently convertible securities were as follows:
NUMBER OUTSTANDING CONVERSION TRIGGER CONTINGENTLY CONVERTIBLE SECURITY MATURITY OF UNITS (IN MILLIONS) PRICE PRICE --------------------------------- -------- --------- ------------- ---------- ------- 4.50% preferred stock.................. N/A 5,000,000 $250 $ 9.89 $11.87 3.375% senior notes.................... 2023 150,000 $150 $10.67 $12.81 2.875% senior notes.................... 2024 287,500 $288 $14.75 $17.70
CMS-72 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The note holders have the right to require us to purchase the 3.375 percent convertible senior notes at par on July 15, 2008, 2013, and 2018. The note holders have the right to require us to purchase the 2.875 percent convertible senior notes at par on December 1, 2011, 2014, and 2019. On or after December 5, 2008, we may cause the 4.50 percent convertible preferred stock to convert if the closing price of our common stock remains at or above $12.86 for 20 of any 30 consecutive trading days. The securities become convertible for a calendar quarter if the price of our common stock remains at or above the trigger price for 20 of 30 consecutive trading days ending on the last trading day of the previous quarter. The trigger price at which these securities become convertible is 120 percent of the conversion price. The conversion and trigger prices are subject to an adjustment under certain circumstances, including payments or distributions to our common stockholders. The conversion and trigger price adjustment will be made only when the cumulative change in conversion and trigger prices is at least one percent. All of our contingently convertible securities require us, if converted, to pay cash up to the principal (or par) amount of the securities and any conversion value in excess of that amount in shares of our common stock. In December 2006, the trigger price contingency was met for our 4.50 percent convertible preferred stock and our 3.375 percent convertible senior notes. As a result, these securities are convertible at the option of the security holders during the three months ended March 31, 2007. As of February 2007, none of the security holders have notified us of their intention to convert these securities. Because the 3.375 percent senior notes are convertible on demand, they are classified as current liabilities. 5: EARNINGS PER SHARE The following table presents the basic and diluted earnings per share computations:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ------ ------ ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) EARNINGS AVAILABLE TO COMMON STOCKHOLDERS Income (Loss) from Continuing Operations................ $ (85) $ (98) $ 127 Less Preferred Dividends................................ (11) (10) (11) ------ ------ ------ Income (Loss) from Continuing Operations Available to Common Stockholders -- Basic......................... (96) (108) 116 Add dilutive impact of Contingently Convertible Securities (net of tax).............................. -- -- 1 ------ ------ ------ Income (Loss) from Continuing Operations Available to Common Stockholders -- Diluted....................... $ (96) $ (108) $ 117 ====== ====== ====== AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO BASIC AND DILUTED EPS Weighted Average Shares -- Basic..................... 219.9 211.8 168.6 Add dilutive impact of Contingently Convertible Securities......................................... -- -- 3.0 Add dilutive Stock Options and Warrants.............. -- -- 0.5 ------ ------ ------ Weighted Average Shares -- Diluted................... 219.9 211.8 172.1 ====== ====== ====== EARNINGS (LOSS) PER AVERAGE COMMON SHARE AVAILABLE TO COMMON STOCKHOLDERS Basic.............................................. $(0.44) $(0.51) $ 0.68 Diluted............................................ $(0.44) $(0.51) $ 0.67
Contingently Convertible Securities: Due to accounting EPS dilution principles, there was no impact to diluted EPS from our contingently convertible securities for the years ended December 31, 2006 and 2005. CMS-73 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Assuming positive income from continuing operations, our contingently convertible securities dilute EPS to the extent that the conversion value, which is based on the average market price of our common stock, exceeds the principal or par value. Had there been positive income from continuing operations, our contingently convertible securities would have contributed an additional 11.3 million shares to the calculation of diluted EPS for 2006 and 10.9 million shares for 2005. For additional details on our contingently convertible securities, see Note 4, Financings and Capitalization. Stock Options and Warrants: For the year ended December 31, 2006, due to accounting EPS dilution principles, there was no impact to diluted EPS for options and warrants to purchase 2.9 million shares of common stock and 1.9 million shares of restricted stock. For the year ended December 31, 2005 there was no impact to diluted EPS for options and warrants to purchase 3.5 million shares of common stock and 1.7 million shares of restricted stock, due to accounting EPS dilution principles. For the year ended December 31, 2004, since the exercise price was greater than the average market price of common stock, there was no impact to diluted EPS from options and warrants to purchase 4.5 million shares of common stock. Convertible Debentures: Due to accounting EPS dilution principles, for the years ended December 31, 2006, 2005, and 2004, there was no impact to diluted EPS from our 7.75 percent convertible subordinated debentures. Using the if- converted method, the debentures would have: - increased the numerator of diluted EPS by $9 million for the years ended December 31, 2006, 2005 and 2004, from an assumed reduction of interest expense, net of tax, and - increased the denominator of diluted EPS by 4.2 million shares. We can revoke the conversion rights if certain conditions are met. 6: FINANCIAL AND DERIVATIVE INSTRUMENTS FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments, or other valuation techniques. The cost and fair value of our long-term financial debt instruments are as follows:
2006 2005 --------------------------------- --------------------------------- UNREALIZED UNREALIZED DECEMBER 31 COST FAIR VALUE GAIN (LOSS) COST FAIR VALUE GAIN (LOSS) ----------- ------ ---------- ----------- ------ ---------- ----------- (IN MILLIONS) Long-term debt(a).................. $6,753 $6,949 $(196) $7,089 $7,315 $(226) Long-term debt -- related parties(b)....................... 178 155 23 307 280 27
-------------- (a) Includes current maturities of $551 million at December 31, 2006 and $289 million at December 31, 2005. Settlement of long-term debt is generally not expected until maturity. (b) Includes current maturities of $129 million at December 31, 2005. CMS-74 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The summary of our available-for-sale investment securities is as follows:
2006 2005 -------------------------------------- -------------------------------------- UNREALIZED UNREALIZED FAIR UNREALIZED UNREALIZED FAIR DECEMBER 31 COST GAINS LOSSES VALUE COST GAINS LOSSES VALUE ----------- ---- ---------- ---------- ----- ---- ---------- ---------- ----- (IN MILLIONS) Nuclear decommissioning investments(a): Equity securities.......... $140 $150 $(4) 286 134 123 (5) 252 Debt securities............ 307 4 (2) 309 287 6 (2) 291 SERP: Equity securities.......... 36 21 -- 57 34 15 -- 49 Debt securities............ 13 -- -- 13 17 -- -- 17
-------------- (a) Nuclear decommissioning investments include cash and cash equivalents and accrued income totaling $7 million at December 31, 2006 and $12 million at December 31, 2005. Unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities. The fair value of available-for-sale debt securities by contractual maturity at December 31, 2006 is as follows:
(IN MILLIONS) ------------- Due in one year or less....................................... $ 38 Due after one year through five years......................... 97 Due after five years through ten years........................ 76 Due after ten years........................................... 111 ---- Total....................................................... $322 ====
In July 2006, we reached an agreement to sell Palisades and the Big Rock ISFSI to Entergy. Entergy will assume responsibility for the future decommissioning of the plant and for storage and disposal of spent nuclear fuel. Accordingly, upon completion of the sale, we will transfer $400 million of nuclear decommissioning trust fund assets to Entergy and retain $205 million. We will also be entitled to receive a return of $147 million, pending either a favorable federal tax ruling regarding the release of the funds, or if no such ruling is issued, after decommissioning of the Palisades site is complete. These estimates fluctuate based on existing market conditions and the closing date of the transaction. The disposition of the retained and receivable nuclear decommissioning funds is subject to regulatory proceedings. Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $91 million at December 31, 2005. They were removed as part of the November 2006 transaction in which we sold our interest in the MCV Partnership. These securities represent funds restricted primarily for future lease payments and are classified as Other assets on our Consolidated Balance Sheets. These investments had original maturity dates of approximately one year or less and, because of their short-term maturities, carrying amounts approximate fair value. DERIVATIVE INSTRUMENTS: In order to limit our exposure to certain market risks, we may enter into various risk management contracts, such as swaps, options, futures, and forward contracts. These contracts, used primarily to manage our exposure to changes in interest rates, commodity prices, and currency exchange rates, are classified as either non-trading or trading. We enter into these contracts using established policies and procedures, under the direction of both: - an executive oversight committee consisting of senior management representatives, and - a risk committee consisting of business unit managers. CMS-75 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative, it is recorded on our consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. From time to time, we enter into cash flow hedges. If a derivative qualifies for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported in AOCL; otherwise, the changes are reported in earnings. For a derivative instrument to qualify for cash flow hedge accounting: - the relationship between the derivative instrument and the forecasted transaction being hedged must be formally documented at inception, - the derivative instrument must be highly effective in offsetting the hedged transaction's cash flows, and - the forecasted transaction being hedged must be probable. If a derivative qualifies for cash flow hedge accounting treatment and gains or losses are recorded in AOCL, those gains or losses will be reclassified into earnings in the same period or periods the hedged forecasted transaction affects earnings. If a cash flow hedge is terminated early because it is determined that the forecasted transaction will not occur, any gain or loss recorded in AOCL at that date is recognized immediately in earnings. If a cash flow hedge is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and then reclassified to earnings when the forecasted transaction affects earnings. The ineffective portion, if any, of all hedges is recognized in earnings. To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of our counterparties. The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because: - they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MWh of electricity or bcf of natural gas), - they qualify for the normal purchases and sales exception, or - there is not an active market for the commodity. Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. If an active market for coal develops in the future, some of these contracts may qualify as derivatives and the resulting mark-to-market impact on earnings could be material. In 2005, the MISO began operating the Midwest Energy Market. As of December 31, 2006, we have determined that, due to the increased liquidity for electricity within the Midwest Energy Market since its inception, it is our best judgment that this market should be considered an active market, as defined by SFAS No. 133. This conclusion does not impact how we account for our electric capacity and energy contracts held in Michigan, however, because these contracts qualify for the normal purchases and sales exception and, as a result, are not required to be marked-to-market. CMS-76 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Derivative accounting is required for certain contracts used to limit our exposure to interest rate risk, commodity price risk, and foreign exchange risk. The following table summarizes our derivative instruments:
DECEMBER 31 2006 2005 ----------- -------------------------- -------------------------- FAIR UNREALIZED FAIR UNREALIZED DERIVATIVE INSTRUMENTS COST VALUE GAIN (LOSS) COST VALUE GAIN (LOSS) ---------------------- ---- ----- ----------- ---- ----- ----------- IN MILLIONS Non-trading: Gas supply option contracts........... $ -- $ -- $ -- $ 1 $ (1) $ (2) FTRs.................................. -- -- -- -- 1 1 Derivative contracts associated with the MCV Partnership: Long-term gas contracts(a)............ -- -- -- -- 205 205 Gas futures, options, and swaps(a).... -- -- -- -- 223 223 CMS ERM contracts: Non-trading electric / gas contracts(b)....................... -- 31 31 -- (63) (63) Trading electric / gas contracts(c)... (11) (68) (57) (3) 100 103 Derivative contracts associated with equity investments in: Shuweihat............................. -- (14) (14) -- (20) (20) Taweelah.............................. (35) (11) 24 (35) (17) 18 Jorf Lasfar........................... -- (5) (5) -- (8) (8) Other................................. -- 1 1 -- 1 1
-------------- (a) The fair value of the MCV Partnership's long-term gas contracts and gas futures, options, and swaps has decreased to $0 as a result of the sale of our interest in the MCV Partnership in November 2006. In conjunction with that sale, our interest in these contracts was also sold and, as a result, we no longer record the fair value of these contracts on our Consolidated Balance Sheets. (b) The fair value of CMS ERM's non-trading electric and gas contracts has increased significantly from December 31, 2005 due to the termination of certain gas contracts. CMS ERM had recorded derivative liabilities, representing cumulative unrealized mark-to-market losses, associated with these gas contracts. As the contracts are now settled, the related derivative liabilities are no longer included in the balance of CMS ERM's non-trading electric and gas contracts. (c) The fair value of CMS ERM's trading electric and gas contracts has decreased significantly from December 31, 2005 due to the termination of certain gas contracts. CMS ERM had recorded derivative assets, representing cumulative unrealized mark-to-market gains, associated with these gas contracts. As the contracts are now settled, the related derivative assets are no longer included in the balance of CMS ERM's trading electric and gas contracts. At December 31, 2005, we recorded the fair value of our gas supply option contracts, FTRs, and the derivative contracts associated with the MCV Partnership in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets. We include the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The fair value of derivative contracts associated with our equity investments is included in Investments -- Enterprises on our Consolidated Balance Sheets. GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses gas supply call and put options to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. As part of regulatory accounting, the mark-to-market gains and losses associated with these options are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on our consolidated balance sheet as a regulatory asset or liability. CMS-77 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FTRS: With the creation of the Midwest Energy Market, FTRs were established. FTRs are financial instruments that manage price risk related to electricity transmission congestion. An FTR entitles its holder to receive compensation (or, conversely, to remit payment) for congestion-related transmission charges. As part of regulatory accounting, the mark-to-market gains and losses associated with these instruments are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on our consolidated balance sheet as a regulatory asset or liability. DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: In November 2006, we sold our interest in the MCV Partnership. In conjunction with that sale, our interest in all of the MCV Partnership's long-term gas contracts and related futures, options, and swaps was sold. Before the sale, we accounted for certain long-term gas contracts and all of the related futures, options, and swaps as derivatives. Long-term gas contracts: The MCV Partnership used long-term gas contracts to purchase and manage the cost of the natural gas it needed to generate electricity and steam. The MCV Partnership determined that certain of these contracts qualified as normal purchases under SFAS No. 133. Accordingly, we did not recognize these contracts at fair value on our Consolidated Balance Sheets. The MCV Partnership also held certain long-term gas contracts that did not qualify as normal purchases because they contained volume optionality or because the gas was not expected to be used to generate electricity or steam in the normal course of business. Accordingly, prior to the sale, we accounted for these contracts as derivatives, with changes in fair value recorded in earnings each quarter. During 2006, through the date of the sale, we recorded a $151 million loss, before considering tax effects and minority interest, associated with the net decrease in fair value of these long-term gas contracts. This loss is included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss). As a result of the sale, we no longer consolidate the MCV Partnership. Accordingly, we will no longer record the fair value of the long-term gas contracts on our Consolidated Balance Sheets and will not be required to record gains or losses related to changes in the fair value of these contracts in earnings. Gas Futures, Options, and Swaps: The MCV Partnership entered into natural gas futures, options, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas. The MCV Partnership used these financial instruments to: - ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam, and - manage price risk by fixing the price to be paid for natural gas on some of its long-term gas contracts. Certain of the futures and swaps held by the MCV Partnership qualified for cash flow hedge accounting and, prior to the sale, we recorded our proportionate share of their mark-to-market gains and losses in AOCL. As of the date of the sale, we had accumulated a net gain of $30 million, net of tax and minority interest, in AOCL representing our proportionate share of mark-to-market gains from these cash flow hedges. After the sale, this amount was reclassified to and recognized in earnings as a reduction of the total loss on the sale in our Consolidated Statements of Income (Loss). The remaining futures, options, and swap contracts held by the MCV Partnership did not qualify as cash flow hedges and we recorded any changes in their fair value in earnings each quarter. During 2006, through the date of the sale, we recorded a $53 million loss, before considering tax effects and minority interest, associated with the net decrease in fair value of these contracts. This loss is included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss). As a result of the sale, we will no longer record the fair value of the futures, options, and swaps on our Consolidated Balance Sheets and will not be required to record gains or losses related to changes in the fair value of these contracts in earnings or AOCL. For additional details on the sale of our interest in the MCV Partnership, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. CMS-78 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts that support CMS Energy's ongoing operations. CMS ERM holds certain contracts for the future purchase and sale of natural gas that will result in physical delivery of the commodity at contractual prices. These forward contracts are generally long- term in nature and are classified as non-trading. CMS ERM also uses various financial instruments, including swaps, options, and futures, to manage commodity price risks associated with its forward purchase and sale contracts and with generation assets owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading activities. In accordance with SFAS No. 133, non-trading and trading contracts that qualify as derivatives are recorded at fair value on our Consolidated Balance Sheets. The resulting assets and liabilities are marked to market each quarter, and changes in fair value are recorded in earnings as a component of Operating Revenue. For trading contracts, these gains and losses are recorded net in accordance with EITF Issue No. 02-03. Contracts that do not meet the definition of a derivative are accounted for as executory contracts (that is, on an accrual basis). DERIVATIVE CONTRACTS ASSOCIATED WITH EQUITY INVESTMENTS: At December 31, 2006, some of our equity method investees held: - interest rate contracts that hedged the risk associated with variable- rate debt, and - foreign exchange contracts that hedged the foreign currency risk associated with payments to be made under operating and maintenance service agreements. We record our proportionate share of the change in fair value of these contracts in AOCL if the contracts qualify for cash flow hedge accounting; otherwise, we record our share in Earnings from Equity Method Investees. There was no ineffectiveness associated with any of the contracts that qualify for cash flow hedge accounting. FOREIGN EXCHANGE DERIVATIVES: At times, we use forward exchange and option contracts to hedge the value of investments in foreign operations. These contracts limit the risk from currency exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on the hedged investments. At December 31, 2006, we had no outstanding foreign exchange contracts. However, the impact of previous hedges on our investments in foreign operations is reflected in AOCL as a component of the foreign currency translation adjustment on our Consolidated Balance Sheets. Gains or losses from the settlement of these hedges are maintained in the foreign currency translation adjustment until we sell or liquidate the hedged investments. At December 31, 2006, our total foreign currency translation adjustment was a net loss of $297 million, which included a net hedging loss of $26 million, net of tax, related to the settlement of these contracts. CREDIT RISK: Our swaps, options, and forward contracts contain credit risk, which is the risk that counterparties will fail to perform their contractual obligations. We reduce this risk through established credit policies. For each counterparty, we assess credit quality by using credit ratings, financial condition, and other available information. We then establish a credit limit for each counterparty based upon our evaluation of credit quality. We monitor the degree to which we are exposed to potential loss under each contract and take remedial action, if necessary. CMS ERM enters into contracts primarily with companies in the electric and gas industry. This industry concentration may have an impact on our exposure to credit risk, either positively or negatively, based on how these counterparties are affected by similar changes in economic conditions, the weather, or other conditions. CMS ERM typically uses industry-standard agreements that allow for netting positive and negative exposures associated with the same counterparty, thereby reducing exposure. These contracts also typically provide for the parties to demand adequate assurance of future performance when there are reasonable grounds for doing so. The following table illustrates our exposure to potential losses at December 31, 2006, if each counterparty within this industry concentration failed to perform its contractual obligations. This table includes contracts accounted for as financial instruments. It does not include trade accounts receivable, derivative contracts that CMS-79 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) qualify for the normal purchases and sales exception under SFAS No. 133, or other contracts that are not accounted for as derivatives.
NET EXPOSURE NET EXPOSURE EXPOSURE FROM INVESTMENT FROM INVESTMENT BEFORE COLLATERAL NET GRADE GRADE COLLATERAL(A) HELD EXPOSURE COMPANIES(B) COMPANIES (%) ------------- ---------- -------- --------------- --------------- (IN MILLIONS) CMS ERM......................... $56 $-- $56 $13 23%
-------------- (a) Exposure is reflected net of payables or derivative liabilities if netting arrangements exist. (b) The majority of the remaining balance of CMS ERM's net exposure was from a counterparty whose credit rating fell below investment grade after December 31, 2005. Based on our credit policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance. 7: RETIREMENT BENEFITS We provide retirement benefits to our employees under a number of different plans, including: - a non-contributory, defined benefit Pension Plan, - a cash balance Pension Plan for certain employees hired between July 1, 2003 and August 31, 2005, - a DCCP for employees hired on or after September 1, 2005, - benefits to certain management employees under SERP, - a defined contribution 401(k) Savings Plan, - benefits to a select group of management under the EISP, and - health care and life insurance benefits under OPEB. Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan's assets are not distinguishable by company. On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of 5 percent of base pay to the existing employees' Savings Plan. No employee contribution is required in order to receive the plan's employer contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP expense was $2 million for the year ended December 31, 2006 and less than $1 million for the year ended December 31, 2005. Effective January 11, 2006, the MPSC electric rate order authorized Consumers to include $33 million of electric pension expense in its electric rates. Effective November 21, 2006, the MPSC gas rate order authorized Consumers to include $22 million of gas pension expense in its gas rates. Due to the volatility of these costs, the orders also established a pension equalization mechanism to track actual costs. If actual pension expenses are greater than the amounts included in rate cases, the difference will be recognized as a regulatory asset for future recovery from customers. If actual pension expenses are less than the amounts included in rate cases, the difference will be recognized as a regulatory liability, and refunded to our customers. The difference between pension expenses allowed in Consumers' rate cases and Consumers' $66 million net pension cost under SFAS No. 87 resulted in the recognition of a regulatory asset of $11 million. CMS-80 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code. SERP trust earnings are taxable and trust assets are included in our consolidated assets. Trust assets were $71 million at December 31, 2006 and $66 million at December 31, 2005. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $78 million at December 31, 2006 and $74 million at December 31, 2005. On April 1, 2006, we implemented a Defined Contribution Supplemental Executive Retirement Plan (DC SERP) and froze further new participation in the defined benefit SERP. The DC SERP provides participants benefits ranging from 5 percent to 15 percent of total compensation. The DC SERP requires a minimum of five years of participation before vesting. Our contributions to the plan, if any, will be placed in a grantor trust. Trust assets were less than $1 million at December 31, 2006. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The DC SERP expense was less than $1 million for the year ended December 31, 2006. 401(k): The employer's match for the 401(k) Savings Plan, which was suspended on September 1, 2002, resumed on January 1, 2005. The employer's match is in CMS Energy Common Stock. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages. The total 401(k) Savings Plan cost was $15 million for the year ended December 31, 2006 and $13 million for the year ended December 31, 2005. Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be an investment option available for new investments in the 401(k) Savings Plan and the employer's match will no longer be in CMS Energy Common Stock. Participants will have the opportunity to reallocate investments in CMS Energy Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment options. At February 20, 2007, there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy Stock Fund. The MCV Partnership sponsors a defined contribution retirement plan and a 401(k) Savings Plan covering all employees. Amounts contributed under these plans were $1 million for the period January 1, 2006 through November 21, 2006 and $1 million for each of the years ended December 31, 2005 and 2004. EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premiums for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was $1 million for each of the years ended December 31, 2006 and 2005. The ABO for the EISP was $5 million at December 31, 2006 and $4 million at December 31, 2005. OPEB: The OPEB plan covers all regular full-time employees covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least 10 full years of applicable continuous service. Regular full-time employees who qualify for a disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs were based on the assumption that costs would increase 10 percent in 2006. Starting in 2007, we will use two health care trend rates: one for retirees under 65 and the other for retirees 65 and over. The two health care trend rates recognize that prescription drug costs are increasing at a faster pace than other medical claim costs and that prescription drug costs make up a larger portion of expenses for retirees age 65 and over. The 2007 rate of increase for OPEB health costs for those under 65 is expected to be 9 percent and for those over 65 is expected to be 10.5 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2011 and for those over 65 by 2013 and thereafter. Effective January 11, 2006, the MPSC electric rate order authorized Consumers to include $28 million of electric OPEB expense in its electric rates. Effective November 21, 2006, the MPSC gas rate order authorized Consumers to include $21 million of gas OPEB expense in its gas rates. Due to the volatility of these costs, the orders also established an OPEB equalization mechanism to track actual costs. If actual OPEB expenses are greater CMS-81 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) than the amounts included in rate cases, the difference will be recognized as a regulatory asset for future recovery from our customers. If actual OPEB expenses are less than the amounts included in rate cases, the difference will be recognized as a regulatory liability, and refunded to our customers. The difference between OPEB expenses allowed in Consumers' rate cases and Consumers' $51 million net OPEB cost under SFAS No. 106 resulted in the recognition of a regulatory asset of $2 million. The MCV Partnership sponsors defined cost postretirement health care plans that cover all full-time employees, except key management. The ABO of the MCV Partnership's postretirement plans was $5 million at December 31, 2005. The MCV Partnership's net periodic postretirement health care cost for the period January 1, 2006 through November 21, 2006 and year ended December 31, 2005 was less than $1 million. The health care cost trend rate assumption affects the estimated costs recorded. A one percentage point change in the assumed health care cost trend assumption would have the following effects:
ONE PERCENTAGE ONE PERCENTAGE POINT INCREASE POINT DECREASE -------------- -------------- (IN MILLIONS) Effect on total service and interest cost component..... $ 19 $ (15) Effect on postretirement benefit obligation............. $220 $(186)
Upon adoption of SFAS No. 106, at the beginning of 1992, we recorded a liability of $466 million for the accumulated transition obligation and a corresponding regulatory asset for anticipated recovery in utility rates. For additional details, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years. The measurement date for all CMS Energy plans is November 30 for 2006, 2005 and 2004. We changed our measurement date in 2004 from December 31 to November 30, which resulted in a $2 million cumulative effect of change in accounting for retirement benefits, net of tax benefit, as a decrease to earnings. We also increased the amount of accrued benefit cost on our Consolidated Balance Sheets by $4 million. The measurement date for the MCV Partnership's plan was December 31 for 2005 and 2004. 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): In September 2006, the FASB issued SFAS No. 158. This standard requires us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 requires us to recognize changes in the funded status of our plans in the year in which the changes occur. This standard also requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of this provision of the standard will have a material effect on our consolidated financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008. The following table recaps the incremental effect of applying SFAS No. 158 on individual line items on our Consolidated Balance Sheets. The adoption of SFAS No. 158 had no effect on our Consolidated Statements of Income (Loss) for the year ended December 31, 2006, or for any prior period presented, and it will not affect our operating results in future periods. Had we not been required to adopt SFAS No. 158 at December 31, 2006, we would have recognized an additional minimum liability pursuant to the provisions of SFAS No. 87. The effect of CMS-82 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) recognizing the additional minimum liability is included in the following table in the column labeled "Before Application of SFAS No. 158:"
BEFORE AFTER APPLICATION OF APPLICATION OF YEAR ENDED DECEMBER 31, 2006 SFAS NO. 158 ADJUSTMENT SFAS NO. 158 ---------------------------- -------------- ---------- -------------- IN MILLIONS Regulatory asset(a).............................. $ 470 $ 680 $ 1,150 Intangible asset................................. 48 (48) -- ------- ----- ------- Total assets..................................... 518 632 1,150 Liability for retirement benefits(b)............. (425) (647) (1,072) Regulatory liabilities -- Income taxes, net(c)... (459) (80) (539) Deferred income taxes............................ (208) 88 (120) ------- ----- ------- Total liabilities................................ (1,092) (639) (1,731) Accumulated other comprehensive loss............. 16 7 23 ------- ----- ------- Total decrease in stockholders' equity........... 16 7 23 ======= ===== =======
-------------- (a) Consumers recognized the cost of their minimum liability prior to the application of SFAS No. 158 and the adjustment resulting from adoption of SFAS No. 158 as a regulatory asset under SFAS No. 71, based upon guidance from the MPSC. (b) Liabilities for retirement benefits include $1.071 billion that are non- current and $1 million that is current at December 31, 2006. (c) The adjustment represents the Medicare D Subsidy tax benefit of implementing SFAS No. 158. Assumptions: The following tables recap the weighted-average assumptions used in our retirement benefits plans to determine benefit obligations and net periodic benefit cost: WEIGHTED AVERAGE FOR BENEFIT OBLIGATIONS:
PENSION & SERP OPEB --------------------- --------------------- YEARS ENDED DECEMBER 31 2006 2005 2004 2006 2005 2004 ----------------------- ---- ---- ---- ---- ---- ---- Discount rate............................... 5.65% 5.75% 6.00% 5.65% 5.75% 6.00% Expected long-term rate of return on plan assets(a)................................. 8.25% 8.50% 8.75% Union..................................... 8.75% Non-Union................................. 6.00% Combined in 2005.......................... 7.75% 8.00% Mortality table(b).......................... 2000 2000 1983 2000 2000 1983 Rate of compensation increase: Pension................................... 4.00% 4.00% 3.50% SERP...................................... 5.50% 5.50% 5.50%
CMS-83 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) WEIGHTED AVERAGE FOR NET PERIODIC BENEFIT COST:
PENSION & SERP OPEB --------------------- --------------------- YEARS ENDED DECEMBER 31 2006 2005 2004 2006 2005 2004 ----------------------- ---- ---- ---- ---- ---- ---- Discount rate............................... 5.75% 5.75% 6.25% 5.75% 5.75% 6.25% Expected long-term rate of return on plan assets(a)................................. 8.50% 8.75% 8.75% Union..................................... 8.75% Non-Union................................. 6.00% Combined in 2005.......................... 8.00% 8.25% Mortality table(b).......................... 2000 2000 1983 2000 2000 1983 Rate of compensation increase: Pension................................... 4.00% 3.50% 3.25% SERP...................................... 5.50% 5.50% 5.50%
-------------- (a) We determine our long-term rate of return by considering historical market returns, the current and future economic environment, the capital market principles of risk and return, and the expert opinions of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed annually for reasonableness and appropriateness. (b) Prior to 2005, we utilized the 1983 Group Annuity Mortality Table. Starting in 2005, we utilize the Combined Healthy RP-2000 Table from the 2000 Group Annuity Mortality Tables. Costs: The following tables recap the costs, other changes in plan assets and benefit obligations incurred in our retirement benefits plans:
PENSION & SERP ------------------- YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Net periodic pension cost Service cost............................................... $ 51 $ 44 $ 37 Interest expense........................................... 88 83 79 Expected return on plan assets............................. (85) (97) (109) Amortization of: Net loss................................................ 43 35 14 Prior service cost...................................... 7 6 6 ---- ---- ----- Net periodic pension cost.................................. 104 71 27 Regulatory adjustment...................................... (11) -- -- ---- ---- ----- Net periodic pension cost after regulatory adjustment........ $ 93 $ 71 $ 27 ==== ==== =====
CMS-84 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
OPEB ------------------ YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Net periodic OPEB cost Service cost................................................ $ 23 $ 23 $ 19 Interest expense............................................ 64 61 58 Expected return on plan assets.............................. (57) (54) (48) Amortization of: Net loss................................................. 20 20 10 Prior service credit..................................... (10) (9) (9) ---- ---- ---- Net periodic OPEB cost...................................... 40 41 30 Regulatory adjustment....................................... (2) -- -- ---- ---- ---- Net periodic OPEB cost after regulatory adjustment............ 38 $ 41 $ 30 ==== ==== ====
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized into net periodic benefits cost over the next fiscal year from regulatory asset is $50 million and from AOCL is $3 million. The estimated net loss and prior service credit for OPEB plans that will be amortized into net periodic benefit cost over the next fiscal year from regulatory asset is $12 million and from AOCL is $1 million. Reconciliations: The following table reconciles the funding of our retirement benefits plans with our retirement benefits plans' liability:
PENSION PLAN SERP OPEB --------------- ----------- --------------- YEARS ENDED DECEMBER 31 2006 2005 2006 2005 2006 2005 ----------------------- ---- ---- ---- ---- ---- ---- IN MILLIONS Benefit obligation at beginning of period................................. $1,510 $1,328 $ 91 $ 83 $1,136 $1,073 Service cost............................. 49 42 2 2 23 23 Interest cost............................ 83 78 5 5 64 61 Plan amendment........................... -- 39 -- 1 -- (19) Actuarial loss (gain).................... 51 146 (2) 4 70 47 Benefits paid............................ (117) (123) (4) (4) (50) (49) ------ ------ ---- ---- ------ ------ Benefit obligation at end of period(a)... 1,576 1,510 92 91 1,243 1,136 ------ ------ ---- ---- ------ ------ Plan assets at fair value at beginning of period................................. 1,018 1,040 -- -- 714 654 Actual return on plan assets............. 126 101 -- -- 73 45 Company contribution..................... 13 -- 4 4 58 63 Actual benefits paid(b).................. (117) (123) (4) (4) (47) (48) ------ ------ ---- ---- ------ ------ Plan assets at fair value at end of period................................. 1,040 1,018 -- -- 798 714 ------ ------ ---- ---- ------ ------ Funded status at end of measurement period................................. (536) (492) (92) (91) (445) (422) Additional VEBA Contributions or Non- Trust Benefit Payments................. -- -- -- -- 14 16 ------ ------ ---- ---- ------ ------ Funded status at December 31............. $ (536) $ (492) $(92) $(91) $ (431) $ (406) ====== ====== ==== ==== ====== ======
-------------- (a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy, which is tax-exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. The Medicare Part D annualized reduction in net OPEB cost was $28 million for 2006 and $24 million for 2005. The CMS-85 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) reduction includes $7 million for the year ended December 31, 2006 and $6 million for the year ended December 31, 2005 in capitalized OPEB costs. (b) We received $3 million in Medicare Part D Subsidy payments for the year ended December 31, 2006. The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans as of December 31, 2005 for all plans combined. (In accordance with SFAS No. 158, we recognized the underfunded status of our defined benefit postretirement plans as a liability on our consolidated balance sheets as of December 31, 2006.)
PENSION PLAN SERP OPEB ------------ ---- ------ YEAR ENDED DECEMBER 31 2005 2005 2005 ---------------------- ---- ---- ---- IN MILLIONS Fair value of plan assets............................... $1,018 $ -- $ 714 Net benefit obligations................................. 1,510 91 1,136 ------ ---- ------ Funded status (plan assets less plan obligations)....... (492) (91) (422) Amounts not recognized Net actuarial loss.................................... 747 8 375 Prior service cost (credit)........................... 56 2 (113) Additional VEBA Contributions or Non-Trust Benefit Payments.............................................. -- -- 16 ------ ---- ------ Net amount recognized................................... $ 311 $(81) $ (144) ====== ==== ======
The following table provides a reconciliation of the amounts recognized on our Consolidated Balance Sheets as of December 31, 2005 for all plans combined:
PENSION PLAN SERP OPEB ------------ ---- ----- YEAR ENDED DECEMBER 31 2005 2005 2005 ---------------------- ---- ---- ---- IN MILLIONS Prepaid benefit cost..................................... $ 311 $ -- $ -- Accrued benefit cost..................................... -- (81) (144) Additional minimum liability............................. (481) -- -- Intangible asset......................................... 56 -- -- AOCL..................................................... 26 -- -- Regulatory asset......................................... 399 -- -- ----- ---- ----- Net amount recognized.................................... $ 311 $(81) $(144) ===== ==== =====
The following table provides pension ABO in excess of plan assets:
YEARS ENDED DECEMBER 31 2006 2005 ----------------------- ---- ---- IN MILLIONS Pension ABO..................................................... $1,240 $1,188 Fair value of pension plan assets............................... 1,040 1,018 ------ ------ Pension ABO in excess of pension plan assets.................... $ 200 $ 170 ====== ======
CMS-86 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) SFAS No. 158 Recognized: The following table recaps the amounts recognized in SFAS No. 158 regulatory assets and AOCL that have not been recognized as components of net periodic benefit cost. For additional details on regulatory assets, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation:"
PENSION & SERP OPEB -------------- ---- YEAR ENDED DECEMBER 31 2006 2006 ---------------------- ---- ---- IN MILLIONS Regulatory assets Net loss.................................................. $676 $416 Prior service cost (credit)............................... 45 (99) AOCL Net loss (gain)........................................... 46 (11) Prior service cost (credit)............................... 4 (4) ---- ---- Total amounts recognized in regulatory assets and AOCL...... $771 $302 ==== ====
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
PENSION OPEB ----------- ----------- NOVEMBER 30 2006 2005 2006 2005 ----------- ---- ---- ---- ---- Asset Category: Fixed Income............................................ 28% 33% 37% 58% Equity Securities:...................................... 62% 65% 63% 40% CMS Energy Common Stock(a)........................... -- -- -- 1% Alternative Strategy................................. 10% 2% -- 1%
-------------- (a) At November 30, 2006, there were no shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. At November 30, 2005, there were no shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. We contributed $56 million to our OPEB plan in 2006 and we plan to contribute $51 million to our OPEB plan in 2007. We contributed $13 million to our Pension Plan in 2006 and we plan to contribute $109 million to our Pension plan in 2007. We have established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor's 500 Index, with lesser allocations to the Standard & Poor's Mid Cap Index, the Small Cap Indexes and a Foreign Equity Index Fund. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. Annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation. We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers, and through direct contributions from the non- utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in a Standard & Poor's 500 Index fund. The fixed-income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed-income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees. CMS-87 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) SFAS No. 132(R) Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:
PENSION SERP OPEB(A) ------- ---- ------- IN MILLIONS 2007...................................................... $ 58 $ 4 $ 54 2008...................................................... 65 4 56 2009...................................................... 73 4 58 2010...................................................... 81 4 60 2011...................................................... 93 4 62 2012-2016................................................. 652 21 333
-------------- (a) OPEB benefit payments are net of employee contributions and expected Medicare Part D prescription drug subsidy payments. The subsidies to be received are estimated to be $5 million for 2007, $6 million each year for 2008 through 2011 and $33 million combined for 2012 through 2016. 8: ASSET RETIREMENT OBLIGATIONS SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard requires companies to record the fair value of the cost to remove assets at the end of their useful life, if there is a legal obligation to remove them. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would increase by $25 million. If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates. FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS: This Interpretation clarified the term "conditional asset retirement obligation" as used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments qualifies as a conditional ARO, as defined by FASB Interpretation No. 47. CMS-88 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following tables describe our assets that have legal obligations to be removed at the end of their useful life:
IN SERVICE ARO DESCRIPTION DATE LONG-LIVED ASSETS TRUST FUND --------------- ---------- ------------------------------------ ------------- (IN MILLIONS) December 31, 2006 Palisades-decommission plant site... 1972 Palisades nuclear plant $598 Big Rock-decommission plant site.... 1962 Big Rock nuclear plant 4 JHCampbell intake/discharge water line.............................. 1980 Plant intake/discharge water line -- Closure of coal ash disposal areas.. Various Generating plants coal ash areas -- Closure of wells at gas storage fields............................ Various Gas storage fields -- Indoor gas services equipment relocations....................... Various Gas meters located inside structures -- Asbestos abatement.................. 1973 Electric and gas utility plant -- Natural gas-fired power plant....... 1997 Gas fueled power plant -- Close gas treating plant and gas wells............................. Various Gas transmission and storage --
ARO ARO LIABILITY CASH FLOW LIABILITY ARO DESCRIPTION 1/1/05(A) INCURRED SETTLED(B) ACCRETION REVISIONS 12/31/05 --------------- --------- -------- ---------- --------- --------- --------- IN MILLIONS Palisades-decommission................. $350 $-- $ -- $25 $-- $375 Big Rock - decommission................ 30 -- (42) 15 24 27 JHCampbell intake line................. -- -- -- -- -- -- Coal ash disposal areas................ 54 -- (5) 5 -- 54 Wells at gas storage fields............ 1 -- -- -- -- 1 Indoor gas services relocations........ 1 -- -- -- -- 1 Natural gas-fired power plant.......... 1 -- -- -- -- 1 Close gas treating plant and gas wells................................ 2 -- (1) -- -- 1 Asbestos abatement..................... 33 -- -- 3 -- 36 ---- --- ---- --- --- ---- Total................................ $472 $-- $(48) $48 $24 $496 ==== === ==== === === ====
ARO ARO LIABILITY CASH FLOW LIABILITY ARO DESCRIPTION 1/1/06 INCURRED SETTLED(B) ACCRETION REVISIONS 12/31/06 --------------- --------- -------- ---------- --------- --------- --------- IN MILLIONS Palisades-decommission................. $375 $-- $ -- $26 $-- $401 Big Rock-decommission.................. 27 -- (28) 3 -- 2 JHCampbell intake line................. -- -- -- -- -- -- Coal ash disposal areas................ 54 -- (2) 5 -- 57 Wells at gas storage fields............ 1 -- -- -- -- 1 Indoor gas services relocations........ 1 -- -- -- -- 1 Natural gas-fired power plant.......... 1 -- -- -- -- 1 Close gas treating plant and gas wells................................ 1 -- -- 1 -- 2 Asbestos abatement..................... 36 -- (3) 2 -- 35 ---- --- ---- --- --- ---- Total................................ $496 $-- $(33) $37 $-- $500 ==== === ==== === === ====
-------------- (a) The ARO liability at January 1, 2005 in the preceding table reflects the ARO liability as if FASB Interpretation No. 47 had been in effect at that time, as required by the Interpretation. Our consolidated financial statements for that period do not reflect the asbestos abatement ARO. As required by SFAS No. 71, we accounted for the implementation of this Interpretation by recording a regulatory asset instead of a cumulative effect of a change in accounting principle. There was no effect on consolidated net income. CMS-89 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (b) These cash payments are included in the Other current and non-current liabilities line in Net cash provided by operating activities in our Consolidated Statements of Cash Flows. In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and related accounting and ratemaking issues for MPSC-jurisdictional electric and gas utilities. In December 2005, the ALJ issued a Proposal for Decision recommending that the MPSC dismiss the proceeding. In March 2006, the MPSC remanded the case to the ALJ for findings and recommendations. In August 2006, the ALJ issued a second Proposal for Decision that included recommendations that the MPSC: - adopt SFAS No. 143 and FERC Order No. 631 for accounting purposes but not for ratemaking purposes, - consider adopting standardized retirement units for certain accounts, - consider revising the method of determining cost of removal, and - withhold approving blanket regulatory asset and regulatory liability accounting treatment related to ARO, stating that modifications to the MPSC's Uniform System of Accounts should precede any such accounting approval. We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities. We cannot predict the outcome of the proceeding. 9: INCOME TAXES CMS Energy and its subsidiaries file a consolidated federal income tax return. Income taxes generally are allocated based on each company's separate taxable income in accordance with the CMS Energy tax sharing agreement. We utilize deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service life of the related properties. We use ITC to reduce current income taxes payable. AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2006, we had AMT credit carryforwards of $271 million that do not expire, tax loss carryforwards of $1.616 billion that expire from 2023 through 2025, including SRLY tax loss carryforwards of $15 million that expire from 2018 through 2020. We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforwards prior to their expiration. In addition, we had general business credit carryforwards of $16 million, capital loss carryforwards of $36 million that expire in 2010 and 2011 and charitable contribution carryforwards of $7 million that expire from 2007 through 2009, for which valuation allowances in each case have been provided. U.S. income taxes are not recorded on the undistributed earnings of foreign subsidiaries that have been or are intended to be reinvested indefinitely. Upon distribution, those earnings may be subject to both U.S. income taxes (adjusted for foreign tax credits or deductions) and withholding taxes payable to various foreign countries. Cumulative undistributed earnings of foreign subsidiaries for which income taxes have not been provided totaled approximately $274 million at December 31, 2006. In 2007, we announced we had signed agreements or plans to sell substantially all of our foreign assets or subsidiaries. These potential sales would result in the recognition in 2007 of approximately $96 million of U.S. tax associated with the change in our determination of our permanent reinvestment of these undistributed earnings. Also, we presently cannot estimate the amount of unrecognized withholding taxes that may result. For additional information, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. The American Jobs Creation Act (AJCA) of 2004 created a one-time opportunity to receive a tax benefit for U.S. corporations that reinvest, in the U.S., dividends received in a year (2005 for CMS Energy) from controlled CMS-90 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) foreign corporations. During 2005, we repatriated $370 million of foreign earnings that qualified for the tax benefit. The net effect of the repatriated earnings were tax benefits of $45 million in 2005 and $21 million in 2004, which were recorded in income from continuing operations. The significant components of income tax expense (benefit) on continuing operations consisted of:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Current income taxes: Federal................................................... $ 129 $ 76 $ -- Federal income tax benefit of operating loss carryforwards.......................................... (31) (70) -- State and local........................................... 1 (3) 3 Foreign................................................... 14 26 9 ----- ----- ---- $ 113 $ 29 $ 12 Deferred income taxes: Federal................................................... $(255) $(141) $ 8 Federal tax benefit of American Jobs Creation Act of 2004................................................... -- (45) (21) State..................................................... -- -- (5) Foreign................................................... (12) 2 6 ----- ----- ---- $(267) $(184) $(12) Deferred ITC, net........................................... (4) (13) (5) ----- ----- ---- Tax expense (benefit)....................................... $(158) $(168) $ (5) ===== ===== ====
Current tax expense includes the settlement of income tax audits for prior years, as well as the provision for 2006 income taxes prior to the use of loss carryforwards. 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 our consolidated 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. The principal components of deferred tax assets (liabilities) recognized on our Consolidated Balance Sheets are as follows:
DECEMBER 31 2006 2005 ----------- ---- ---- (IN MILLIONS) Property....................................................... $ (790) $ (764) Securitized costs.............................................. (177) (172) Employee benefits.............................................. 38 (67) Gas inventories................................................ (168) (148) Tax loss and credit carryforwards.............................. 867 648 SFAS No. 109 regulatory liabilities, net....................... 189 159 Foreign investments inflation indexing......................... 86 -- Valuation allowances........................................... (116) (10) Other, net..................................................... 106 2 ------- ------- Net deferred tax assets/(liabilities)........................ $ 35 $ (352) ======= ======= Deferred tax liabilities....................................... $(1,324) $(1,325) Deferred tax assets, net of valuation reserves................. 1,359 973 ------- ------- Net deferred tax assets/(liabilities)........................ $ 35 $ (352) ======= =======
During 2006, our Venezuelan investments employed inflation indexing to their balance sheet, most notably to fixed assets, resulting in a tax basis increase for local tax purposes. Such adjustments are not recognized for U.S. purposes; thus, a basis difference exists. We do not believe it to be more likely than not that we will benefit from CMS-91 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) increased depreciation deductions attributable to this write up, due to income limitations. Therefore the deferred tax assets have been fully reserved. In June 2006, the IRS concluded its most recent audit of CMS Energy and its subsidiaries and proposed changes to taxable income for the years ended December 31, 1987 through December 31, 2001. The proposed overall cumulative increase to taxable income related primarily to the disallowance of the simplified service cost method with respect to certain self-constructed utility assets. We have accepted these proposed adjustments to taxable income, which resulted in the payment of $76 million of tax and a reduction of our income tax provision of $62 million, net of interest expense, primarily for the restoration and utilization of previously written off income tax credits. The actual income tax expense (benefit) on continuing operations differs from the amount computed by applying the statutory federal tax rate of 35 percent to income / (loss) before income taxes as follows:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Income (loss) from continuing operations before income taxes Domestic................................................. $(129) $(463) $ 199 Foreign.................................................. (114) 197 (77) ----- ----- ----- Total................................................. (243) (266) 122 Statutory federal income tax rate.......................... x 35% x 35% x 35% ----- ----- ----- Expected income tax expense (benefit)...................... (85) (93) 42 Increase (decrease) in taxes from: Property differences..................................... 19 15 13 Income tax effect of foreign investments................. (28) (24) (25) AJCA foreign dividends benefit........................... -- (45) (21) ITC amortization......................................... (4) (4) (6) State and local income taxes, net of federal benefit..... -- (2) (1) Return to accrual adjustments............................ (7) (1) (5) Medicare Part D exempt income............................ (10) (6) (6) Tax exempt income........................................ (3) (3) (3) Tax contingency reserves................................. -- (5) 5 Valuation allowance...................................... 20 -- -- IRS Settlement / Credit Restoration...................... (62) -- -- Other, net............................................... 2 -- 2 ----- ----- ----- Recorded income tax benefit................................ $(158) $(168) $ (5) ----- ----- ----- Effective tax rate......................................... 65.0% 63.2% (4.1)% ===== ===== =====
During 2006, the valuation allowance increased by $20 million. The increase was due to a $12 million increase in the allowance attributable to the capital loss on our November 2006 disposition of the MCV Partnership and a $14 million increase for the anticipated future capital loss on our GasAtacama investment. These increases were offset by a $3 million reduction in the valuation allowance for the anticipated use of prior year capital loss carryovers as well as for $3 million of allowance attributable to charitable contributions and tax credits that expired on December 31, 2006. The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities at December 31, 2006 are adequate for all years. FIN 48, Accounting for Uncertainty in Income Taxes: In June 2006, the FASB issued FIN 48, effective for us January 2007. This interpretation provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management's best judgment, it is greater than 50 percent likely that the taxing CMS-92 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) authority will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return. Our policy is to include interest and penalties accrued on uncertain tax positions as part of the related tax liability on our consolidated balance sheet and as part of the income tax expense in our consolidated income statement. The impact from adopting FIN 48 should be recorded as a cumulative adjustment to the beginning retained earnings balance and a corresponding adjustment to a current or non-current tax liability. At this time, we are continuing to evaluate the impact of FIN 48 on our consolidated financial statements. 10: EXECUTIVE INCENTIVE COMPENSATION We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee directors based on their contributions to the successful management of the company. The Plan has a five-year term, expiring in May 2009. All grants under the Plan for 2006 and 2005 were in the form of restricted stock. Restricted stock awards are outstanding shares to which the recipient has full voting and dividend rights and vest 100 percent after three years of continued employment. Restricted stock awards granted to officers in 2006, 2005, and 2004 are also subject to the achievement of specified levels of total shareholder return, including a comparison to a peer group of companies. All restricted stock awards are subject to forfeiture if employment terminates before vesting. However, if certain minimum service requirements are met, restricted shares may continue to vest upon retirement or disability and vest fully if control of CMS Energy changes, as defined by the Plan. In April 2006, we amended the Plan to allow awards not subject to achievement of total shareholder return to vest fully upon retirement, subject to the participant not accepting employment with a direct competitor. This modification did not have a material impact on our consolidated financial statements. The Plan also allows for stock options, stock appreciation rights, phantom shares, and performance units. None of which were granted in 2006 or 2005. Select participants may elect to receive all or a portion of their incentive payments under the Officer's Incentive Compensation Plan in the form of cash, shares of restricted common stock, shares of restricted stock units, or any combination of these. These participants may also receive awards of additional restricted common stock or restricted stock units, provided the total value of these additional grants does not exceed $2.5 million for any fiscal year. Shares awarded or subject to stock options, phantom shares, and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such awards to any participant exceed 250,000 shares in any fiscal year. We may issue awards of up to 4,382,800 shares of common stock under the Plan at December 31, 2006. Shares for which payment or exercise is in cash, as well as forfeited shares or stock options may be awarded or granted again under the Plan. The following table summarizes restricted stock activity under the Plan:
WEIGHTED-AVERAGE NUMBER OF GRANT DATE RESTRICTED STOCK SHARES FAIR VALUE ---------------- --------- ---------------- Nonvested at December 31, 2005........................... 1,682,056 $10.64 Granted................................................ 587,830 $13.84 Vested................................................. (308,698) $ 7.71 Forfeited.............................................. (58,750) $10.82 --------- ------ Nonvested at December 31, 2006........................... 1,902,438 $12.10 ========= ======
CMS-93 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective. We expense the fair value over the required service period of the awards. As a result, we recognize all compensation expense for share-based awards with accelerated service provisions upon retirement by the period in which the employee becomes eligible to retire. The total fair value of shares vested was $4 million in 2006, $4 million in 2005, and $1 million in 2004. We calculate the fair value of restricted shares granted based on the price of our common stock on the grant date and expense the fair value over the required service period. Compensation expense related to restricted stock was $9 million in 2006, $4 million in 2005, and $2 million in 2004. The total related income tax benefit recognized in income was $3 million in 2006, $2 million in 2005, and $1 million in 2004. At December 31, 2006, there was $10 million of total unrecognized compensation cost related to restricted stock. We expect to recognize this cost over a weighted-average period of 1.3 years. The following table summarizes stock option activity under the Plan:
OPTIONS OUTSTANDING, FULLY VESTED, WEIGHTED-AVERAGE AGGREGATE AND WEIGHTED-AVERAGE REMAINING INTRINSIC STOCK OPTIONS EXERCISABLE EXERCISE PRICE CONTRACTUAL TERM VALUE ------------- ------------- ---------------- ---------------- ------------- (IN MILLIONS) Outstanding at December 31, 2005.... 3,541,338 $21.21 5.4 years $(24) Granted........................... -- -- Exercised......................... (137,500) $ 7.39 Cancelled or Expired.............. (490,568) $30.53 --------- ------ --------- ---- Outstanding at December 31, 2006.... 2,913,270 $20.29 4.7 years $(10) ========= ====== ========= ====
Stock options give the holder the right to purchase common stock at a price equal to the fair value of our common stock on the grant date. Stock options are exercisable upon grant, and expire up to 10 years and one month from the grant date. We issue new shares when participants exercise stock options. The total intrinsic value of stock options exercised was $1 million in 2006, $2 million in 2005, and $2 million in 2004. Cash received from exercise of these stock options was $1 million for the year ended December 31, 2006. Since we have utilized tax loss carryforwards, we were not able to realize the excess tax benefits upon exercise of stock options. Therefore, we did not recognize the related excess tax benefits in equity. 11: LEASES Lessee: We lease various assets, including service vehicles, railcars, construction equipment, office furniture, and buildings. We purchase renewable energy under certain power purchase agreements, as required by the MPSC. In accordance with SFAS No. 13, we account for these power purchase agreements as capital and operating leases. Operating leases for coal-carrying railcars have lease terms expiring over the next 15 years. These leases contain fair market value extension and buyout provisions, with some providing for predetermined extension period rentals. Capital leases for our vehicle fleet operations have a maximum term of 120 months and TRAC end-of-life provisions. The capital lease for furniture terminates in 2013, but provides for an early buyout in April 2008. Power purchase agreements range from 7 to 20 years. Most of our power purchase agreements contain options at the end of the initial contract term to renew the agreement annually. CMS-94 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Consumers is authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. The following table summarizes our capital and operating lease expenses:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Capital lease expense.......................................... $15 $14 $13 Operating lease expense........................................ 19 18 14 Income from subleases.......................................... (2) (2) (1) === === ===
Minimum annual rental commitments under our non-cancelable leases at December 31, 2006 are:
CAPITAL OPERATING LEASES LEASES ------- --------- (IN MILLIONS) 2007........................................................... $13 $ 25 2008........................................................... 12 24 2009........................................................... 11 20 2010........................................................... 9 17 2011........................................................... 7 17 2012 and thereafter............................................ 29 61 --- ---- Total minimum lease payments(a)................................ 81 $164 ==== Less imputed interest.......................................... 26 --- Present value of net minimum lease payments.................... 55 Less current portion........................................... 13 --- Non-current portion............................................ $42 ===
-------------- (a) Minimum payments have not been reduced by minimum sublease rentals of $4 million due in the future under noncancelable subleases. Lessor: We have a 44 percent ownership interest in a 31-mile intrastate pipeline that runs from Coldwater Township, Michigan to Hanover Township, Michigan. We lease our interest in the pipeline through a direct finance lease. The lease expires in October 2031, with an annual option to extend the lease. We sell power, through the Takoradi power plant located in the Republic of Ghana, Africa, under a power purchase agreement with the Volta River Authority. In accordance with SFAS No. 13, we account for this transaction as a direct finance lease. The initial lease term of the agreement expires in 2025. CMS-95 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table summarizes the net investment in direct finance leases at December 31, 2006:
DIRECT FINANCE LEASES --------------------- (IN MILLIONS) 2007........................................................... $ 25 2008........................................................... 25 2009........................................................... 25 2010........................................................... 24 2011........................................................... 24 2012 and thereafter............................................ 333 ---- Total minimum lease payments................................... 456 Less unearned income........................................... 346 ---- Net investment in direct finance leases........................ 110 Less current portion........................................... 1 ---- Non-current portion............................................ $109 ====
12: PROPERTY, PLANT, AND EQUIPMENT The following table is a summary of our property, plant, and equipment:
ESTIMATED DEPRECIABLE DECEMBER 31 LIFE IN YEARS 2006 2005 ----------- ------------- ------ ------ (IN MILLIONS) Electric: Generation........................................... 13-85 $3,573 $3,487 Distribution......................................... 12-75 4,425 4,226 Other................................................ 7-40 421 404 Capital leases(a).................................... 85 87 Gas: Underground storage facilities(b).................... 30-65 263 262 Transmission......................................... 15-75 465 416 Distribution......................................... 40-75 2,216 2,141 Other................................................ 7-50 300 306 Capital leases(a).................................... 29 26 Enterprises: IPP.................................................. 3-40 565 813 CMS Gas Transmission................................. 3-40 116 131 CMS Electric and Gas................................. 2-30 120 99 Other................................................ 4-25 33 25 Other:................................................. 7-71 31 25 Construction work-in-progress.......................... 651 520 Less accumulated depreciation, depletion, and amortization(c)...................................... 5,317 5,123 ------ ------ Net property, plant, and equipment(d)(e)............... $7,976 $7,845 ====== ======
-------------- (a) Capital leases presented in this table are gross amounts. Amortization of capital leases was $59 million in 2006 and $54 million in 2005. Capital lease additions were $7 million and capital lease retirements and adjustments were $6 million in 2006. Capital lease additions were $12 million and capital lease retirements and adjustments were $7 million in 2005. (b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2006 and December 31, 2005, which is not subject to depreciation. CMS-96 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (c) At December 31, 2006, accumulated depreciation, depletion, and amortization included $4.982 billion from our public utility plant assets and $335 million from other plant assets. At December 31, 2005, accumulated depreciation, depletion, and amortization included $4.804 billion from our public utility plant assets and $319 million from other plant assets. (d) At December 31, 2006, public utility plant additions were $470 million and public utility plant retirements, including other plant adjustments, were $82 million. At December 31, 2005, public utility plant additions were $450 million and public utility plant retirements, including other plant adjustments, were $64 million. (e) Included in net property, plant and equipment are intangible assets related primarily to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization lives for software development costs range from seven to twelve years. The estimated amortization life for leasehold improvements is the life of the lease. Other intangible amortization lives range from 13 to 75 years. The following tables summarize our intangible assets:
INTANGIBLE ACCUMULATED ASSET, DECEMBER 31, 2006 GROSS COST AMORTIZATION NET ----------------- ---------- ------------ ---------- (IN MILLIONS) Software development................................ $204 $153 $ 51 Rights of way....................................... 115 32 83 Leasehold improvements.............................. 19 15 4 Franchises and consents............................. 19 10 9 Other intangibles................................... 29 17 12 ---- ---- ---- Total............................................... $386 $227 $159 ==== ==== ====
INTANGIBLE ACCUMULATED ASSET, DECEMBER 31, 2005 GROSS COST AMORTIZATION NET ----------------- ---------- ------------ ---------- (IN MILLIONS) Software development................................ $200 $135 $ 65 Rights of way....................................... 103 29 74 Leasehold improvements.............................. 19 14 5 Franchises and consents............................. 19 9 10 Other intangibles................................... 42 19 23 ---- ---- ---- Total............................................... $383 $206 $177 ==== ==== ====
Pretax amortization expense related to these intangible assets was $23 million for the year ended December 31, 2006, $21 million for the year ended December 31, 2005, and $21 million for the year ended December 31, 2004. Amortization of intangible assets is forecasted to range between $14 million and $23 million per year over the next five years. 13: EQUITY METHOD INVESTMENTS We account for certain investments in other companies, partnerships, and joint ventures by the equity method of accounting in accordance with APB Opinion No. 18, where ownership is more than 20 percent but less than a majority. Earnings from equity method investments was $89 million in 2006, $125 million in 2005, and $115 million in 2004. The amount of consolidated retained earnings that represents undistributed earnings from these equity method investments was $14 million as of December 31, 2006 and $17 million as of December 31, 2005. CMS-97 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Our most significant equity method investments are: - a 50 percent interest in Jorf Lasfar, and - a 40 percent interest in Taweelah. If any of our equity method investments have assets or income from continuing operations exceeding 10 percent of our consolidated assets or income, summarized financial data of that subsidiary must be presented in the footnotes. If any of our equity method investments have assets or income from continuing operations exceeding 20 percent of our consolidated assets or income, separate, audited financial statements must be presented as an exhibit to our Form 10-K. At December 31, 2006, Jorf Lasfar exceeded the 10 percent and 20 percent thresholds. At December 31, 2005, Jorf Lasfar exceeded the 10 percent threshold and no equity method investments exceeded the 20 percent threshold. At December 31, 2004, Jorf Lasfar exceeded the 20 percent threshold and both Jorf Lasfar and Taweelah exceeded the 10 percent threshold. Summarized financial information for these equity method investments is as follows: Income Statement Data
Year Ended December 31, 2006 ------------------------- Jorf All Lasfar(a) Others Total --------- ------ ----- (In Millions) Operating revenue........................................ $482 $1,611 $2,093 Operating expenses....................................... 317 1,283 1,600 ---- ------ ------ Operating income......................................... 165 328 493 Other expense, net....................................... 57 195 252 ---- ------ ------ Net income............................................... $108 $ 133 $ 241 ==== ====== ======
Year Ended December 31, 2005 ------------------------- Jorf All Lasfar(a) Others Total --------- ------ ------ (In Millions) Operating revenue........................................ $508 $1,550 $2,058 Operating expenses....................................... 340 1,190 1,530 ---- ------ ------ Operating income......................................... 168 360 528 Other expense, net....................................... 56 187 243 ---- ------ ------ Net income............................................... $112 $ 173 $ 285 ==== ====== ======
CMS-98 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Year Ended December 31, 2004 ----------------------------------- Jorf All Lasfar(a) Taweelah Others Total --------- -------- ------ ------ (In Millions) Operating revenue.................................. $461 $99 $1,448 $2,008 Operating expenses................................. 282 40 1,207 1,529 ---- --- ------ ------ Operating income................................... 179 59 241 479 Other expense, net................................. 53 23 140 216 ---- --- ------ ------ Net income......................................... $126 $36 $ 101 $ 263 ==== === ====== ======
Balance Sheet Data
December 31, 2006 ------------------------- Jorf All Lasfar(a) Others Total --------- ------ ------ (In Millions) Assets Current assets......................................... $ 239 $ 555 $ 794 Property, plant and equipment, net..................... 15 2,931 2,946 Other assets........................................... 1,047 480 1,527 ------ ------ ------ $1,301 $3,966 $5,267 ====== ====== ====== Liabilities Current liabilities.................................... $ 272 $ 546 $ 818 Long-term debt and other non-current liabilities....... 403 2,721 3,124 Equity................................................. 626 699 1,325 ------ ------ ------ $1,301 $3,966 $5,267 ====== ====== ======
December 31, 2005 ------------------------- Jorf All Lasfar(a) Others Total --------- ------ ------ Assets Current assets......................................... $ 264 $ 554 $ 818 Property, plant and equipment, net..................... 15 3,372 3,387 Other assets........................................... 1,022 516 1,538 ------ ------ ------ $1,301 $4,442 $5,743 ====== ====== ====== Liabilities Current liabilities.................................... $ 241 $ 458 $ 699 Long-term debt and other non-current liabilities....... 441 2,914 3,355 Equity................................................. 619 1,070 1,689 ------ ------ ------ $1,301 $4,442 $5,743 ====== ====== ======
-------------- (a) Our investment in Jorf Lasfar was $313 million at December 31, 2006 and $310 million at December 31, 2005. Our share of net income from Jorf Lasfar was $54 million for the year ended December 31, 2006, $56 million for the year ended December 31, 2005, and $63 million for the year ended December 31, 2004. CMS-99 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) In February 2007, we reached an agreement to sell our ownership interests in businesses in the Middle East, Africa, and India, including Jorf Lasfar and Taweelah. We expect to close the sale in the middle of 2007. For additional details on the sale of our interest in certain equity method investees, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. 14: JOINTLY OWNED REGULATED UTILITY FACILITIES We have investments in jointly owned regulated utility facilities as shown in the following table:
Accumulat- Construct- Net ed ion Invest- Deprecia- Work in Ownership ment(a) tion Progress Share ---------- ---------- ---------- DECEMBER 31 (Percent) 2006 2005 2006 2005 2006 2005 ----------- --------- ---- ---- ---- ---- ---- ---- (In Millions) Campbell Unit 3......................... 93.3 $262 $270 $370 $354 $353 $258 Ludington............................... 51.0 68 72 95 92 1 1 Distribution............................ Various 98 100 47 45 4 9
-------------- (a) Net investment is the amount of utility plant in service less accumulated depreciation. The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant's undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities. 15: REPORTABLE SEGMENTS Our reportable segments consist of business units organized and managed by their products and services. We evaluate performance based upon the net income of each segment. We operate principally in three reportable segments: electric utility, gas utility, and enterprises. The electric utility segment consists of regulated activities associated with the generation and distribution of electricity in the state of Michigan through our subsidiary, Consumers. The gas utility segment consists of regulated activities associated with the transportation, storage, and distribution of natural gas in the state of Michigan through our subsidiary, Consumers. The enterprises segment consists of: - investing in, acquiring, developing, constructing, managing, and operating non-utility power generation plants, electric distribution assets, and natural gas facilities in the United States and abroad, and - providing gas, oil, and electric marketing services to energy users. Accounting policies of our segments are the same as we describe in the summary of significant accounting policies. Our consolidated financial statements reflect the assets, liabilities, revenues, and expenses directly related to the individual segments where it is appropriate. We allocate accounts between the segments where common accounts are attributable to more than one segment. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, other operation and maintenance expense, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue. Pension provisions are allocated based on labor dollars. We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income (loss) by segment. The "Other" segment includes corporate interest and other, discontinued operations, CMS-100 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) certain deferred income taxes and the cumulative effect of accounting changes. The following tables show our financial information by reportable segment:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Operating Revenues Electric utility..................................... $ 3,302 $ 2,695 $ 2,583 Gas utility.......................................... 2,373 2,483 2,081 Enterprises.......................................... 1,135 1,110 808 ------- ------- ------- $ 6,810 $ 6,288 $ 5,472 ======= ======= ======= Earnings from Equity Method Investees Enterprises.......................................... $ 87 $ 124 $ 113 Other................................................ 2 1 2 ------- ------- ------- $ 89 $ 125 $ 115 ======= ======= ======= Depreciation, Depletion, and Amortization Electric utility..................................... $ 380 $ 292 $ 189 Gas utility.......................................... 122 117 112 Enterprises.......................................... 71 115 129 Other................................................ 3 1 1 ------- ------- ------- $ 576 $ 525 $ 431 ======= ======= ======= Interest Charges Electric utility..................................... $ 164 $ 132 $ 203 Gas utility.......................................... 73 68 64 Enterprises.......................................... 79 76 87 Other................................................ 190 208 275 ------- ------- ------- $ 506 $ 484 $ 629 ======= ======= ======= Income Tax Expense (Benefit) Electric utility..................................... $ 95 $ 85 $ 120 Gas utility.......................................... 18 39 40 Enterprises.......................................... (102) (176) (46) Other................................................ (169) (116) (119) ------- ------- ------- $ (158) $ (168) $ (5) ======= ======= ======= Net Income (Loss) Available to Common Stockholders Electric utility..................................... $ 199 $ 153 $ 223 Gas utility.......................................... 37 48 71 Enterprises.......................................... (158) (142) 19 Other................................................ (168) (153) (203) ------- ------- ------- $ (90) $ (94) $ 110 ======= ======= ======= Investments in Equity Method Investees Enterprises.......................................... $ 588 $ 712 $ 729 Other................................................ 10 13 23 ------- ------- ------- $ 598 $ 725 $ 752 ======= ======= =======
CMS-101 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Total Assets Electric utility(a).................................. $ 8,516 $ 7,755 $ 7,289 Gas utility(a)....................................... 3,950 3,609 3,187 Enterprises.......................................... 2,339 4,130 4,980 Other................................................ 566 547 416 ------- ------- ------- $15,371 $16,041 $15,872 ======= ======= ======= Capital Expenditures(b) Electric utility..................................... $ 462 $ 384 $ 360 Gas utility.......................................... 172 168 137 Enterprises.......................................... 42 50 37 Other................................................ 1 3 1 ------- ------- ------- $ 677 $ 605 $ 535 ======= ======= =======
Geographic Areas(c)
2006 2005 2004 ---- ---- ---- (IN MILLIONS) United States Operating Revenue..................................... $ 6,140 $ 5,894 $ 5,163 Operating Income (Loss)............................... (13) (461) 586 Total Assets.......................................... $14,123 $14,675 $14,419 International Operating Revenue..................................... $ 670 $ 394 $ 309 Operating Income (Loss)............................... (20) 187 7 Total Assets.......................................... $ 1,248 $ 1,366 $ 1,453
-------------- (a) Amounts include a portion of Consumers' other common assets attributable to both the electric and gas utility businesses. (b) Amounts include electric restructuring implementation plan, purchase of nuclear fuel, and capital lease additions. Amounts also include a portion of Consumers' capital expenditures for plant and equipment attributable to both the electric and gas utility businesses. (c) Revenues are based on the country location of customers. 16: CONSOLIDATION OF VARIABLE INTEREST ENTITIES Until their sale in November 2006, we had a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Prior to their sale, we were the primary beneficiary of both the MCV Partnership and the FMLP because Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement and Consumers, through its ownership interest in the FMLP, held a 35 percent lessor interest in the MCV Facility. Therefore, we consolidated these partnerships into our consolidated financial statements as of and for the year ended December 31, 2005. Upon the sale of our interests in the MCV Partnership and the FMLP, we are no longer the primary beneficiary of these entities and the entities were deconsolidated. For additional details on the sale of our interests in the MCV Partnership and the FMLP, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. These partnerships had third-party obligations totaling $482 million at December 31, 2005. Property, plant, and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, CMS-102 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 2005. The creditors of these partnerships did not have recourse to the general credit of Consumers. At December 31, 2005, the MCV Partnership had total assets of $1.318 billion and a net loss of $917 million for the year. We are the primary beneficiary of three other variable interest entities. We have 50 percent partnership interests each in the T.E.S. Filer City Station Limited Partnership, the Grayling Generating Station Limited Partnership, and the Genesee Power Station Limited Partnership. Additionally, we have operating and management contracts and are the primary purchaser of power from each partnership through long-term power purchase agreements. Collectively, these interests make us the primary beneficiary of these entities. Therefore, we consolidated these partnerships into our consolidated financial statements for all periods presented. These partnerships have third-party obligations totaling $97 million at December 31, 2006 and $108 million at December 31, 2005. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $157 million at December 31, 2006 and $163 million at December 31, 2005. Other than through outstanding letters of credit and guarantees of $5 million, the creditors of these partnerships do not have recourse to the general credit of CMS Energy. Additionally, we hold interests in variable interest entities in which we are not the primary beneficiary. The following chart details our involvement in these entities at December 31, 2006:
INVESTMENT OPERATING TOTAL NAME NATURE OF THE INVOLVEMENT BALANCE AGREEMENT WITH GENERATING (OWNERSHIP INTEREST) ENTITY COUNTRY DATE (IN MILLIONS) CMS ENERGY CAPACITY -------------------- ------------- ------- ----------- ------------- -------------- ---------- Taweelah (40%).......... Generator United Arab 1999 Emirates $ 83 Yes 777MW Jubail (25%)............ Generator Saudi Arabia 2001 -- No 250MW Shuweihat (20%)......... Generator United Arab 2001 Emirates 56 Yes 1,500MW ---- ------- Total................... $139 2,527MW ==== =======
Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $139 million, and letters of credit, guarantees, and indemnities totaling $47 million. In February 2007, we entered into an Agreement of Purchase and Sale with TAQA to sell our ownership interest in businesses in the Middle East, Africa, and India for $900 million. Businesses included in the sale are Taweelah, Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We expect to close on the sale in the middle of 2007. For additional details on the sale of our interests in these entities, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations. CMS-103 CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 17: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
2006 --------------------------------------- QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31(D) -------------- -------- ------- -------- ---------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Operating revenue................................. $2,032 $1,396 $1,462 $1,920 Operating income (loss)........................... (8) 97 (1) (121) Income (loss) from continuing operations(a)....... (25) 73 (102) (31) Income from discontinued operations(b)............ 1 2 1 2 Net income (loss)................................. (24) 75 (101) (29) Preferred dividends............................... 3 3 2 3 Net income (loss) available to common stockholders.................................... (27) 72 (103) (32) Income (loss) from continuing operations per average common share -- basic................... (0.13) 0.32 (0.47) (0.16) Income (loss) from continuing operations per average common share -- diluted................. (0.13) 0.30 (0.47) (0.16) Basic earnings (loss) per average common share(a)........................................ (0.12) 0.33 (0.47) (0.15) Diluted earnings (loss) per average common share(a)........................................ (0.12) 0.31 (0.47) (0.15) Common stock prices(c) High............................................ 15.22 13.66 14.79 16.95 Low............................................. 12.95 12.46 12.92 14.55
--------------
2005 --------------------------------------- QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31(E) -------------- -------- ------- -------- ---------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Operating revenue................................. $1,845 $1,230 $1,307 $1,906 Operating income (loss)........................... 451 95 (804) (16) Income (loss) from continuing operations(a)....... 152 30 (263) (17) Income from discontinued operations(b)............ -- -- -- 14 Net income (loss)................................. 152 30 (263) (3) Preferred dividends............................... 2 3 2 3 Net income (loss) available to common stockholders.................................... 150 27 (265) (6) Income (loss) from continuing operations per average common share -- basic................... 0.77 0.12 (1.21) (0.09) Income (loss) from continuing operations per average common share -- diluted................. 0.74 0.12 (1.21) (0.09) Basic earnings (loss) per average common share(a)........................................ 0.77 0.12 (1.21) (0.03) Diluted earnings (loss) per average common share(a)........................................ 0.74 0.12 (1.21) (0.03) Common stock prices(c) High............................................ 13.38 15.16 16.71 16.48 Low............................................. 9.81 12.56 14.98 13.39
-------------- (a) Sum of the quarters may not equal the annual earnings (loss) per share due to changes in shares outstanding. (b) Net of tax. (c) Based on New York Stock Exchange -- Composite transactions. (d) The quarter ended December 31, 2006 includes a $41 million net loss on the sale of our investment in the MCV Partnership including the negative impact of the associated asset impairment charge. The quarter also includes an $80 million net after-tax charge resulting from our agreement to settle shareholder class action lawsuits. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations and Note 3, Contingencies. (e) The quarter ended December 31, 2005 includes a $26 million after-tax charge related to environmental remediation at Bay Harbor. For additional details, see Note 3, Contingencies. CMS-104 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders of CMS Energy Corporation We have audited the accompanying consolidated balance sheets of CMS Energy Corporation (a Michigan Corporation) as of December 31, 2006 and 2005, and the related consolidated statements of income (loss), common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedules listed in the Index at Item 15(a)(2). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a former 49% owned variable interest entity which has been consolidated through the date of sale, November 21, 2006 (Note 2), which statements reflect total assets constituting 8.2% in 2005, and total revenues constituting 8.0% in 2006, 9.4% in 2005 and 11.9% in 2004 of the related consolidated totals. We also did not audit the 2004 financial statements of Jorf Lasfar Energy Company S.C.A. (which represents an investment accounted for under the equity method of accounting). CMS Energy Corporation's equity in the net income of Jorf Lasfar Energy Company S.C.A. is stated at $63 million for the year ended December 31, 2004. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for the periods indicated above for Midland Cogeneration Venture Limited Partnership and Jorf Lasfar Energy Company S.C.A., respectively, is based solely on the reports of the other auditors. 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 and the reports of other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CMS Energy Corporation at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Note 7 to the consolidated financial statements, in 2006, the Company adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106 and 132(R)." As discussed in Note 10 to the consolidated financial statements, in 2006, the Company adopted FASB Statement of Financial Accounting Standards No. 123(R) "Share-Based Payment." In addition, as discussed in Note 8 to the consolidated financial statements, in 2005 the Company adopted FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." As discussed in Note 7 to the consolidated financial statements, in 2004 the Company changed its measurement date for all CMS Energy Corporation pension and postretirement plans. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of CMS Energy Corporation's internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2007, expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Detroit, Michigan February 21, 2007 CMS-105 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners and the Management Committee of Midland Cogeneration Venture Limited Partnership: In our opinion, the accompanying balance sheets and the related statements of operations, of partners' equity (deficit) and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and December 31, 2005, and the results of its operations and its cash flows for the period ended November 21, 2006 and the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP February 19, 2007 CMS-106 REPORT OF INDEPENDENT AUDITORS To the Management Committee and Stockholders of Jorf Lasfar Energy Company S.C.A. B.P. 99 Sidi Bouzid El Jadida We have audited the accompanying balance sheets of Jorf Lasfar Energy Company S.C,A (the "Company") as of December 31, 2004, 2003 and 2002, and the related statements of income, of stockholders' equity and of cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). 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 statements presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Jorf Lasfar Energy Company S.C.A at December 31, 2004, 2003 and 2002, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. /s/ Price Waterhouse Casablanca, Morocco, February 11, 2005 CMS-107 (CONSUMERS ENERGY LOGO) 2006 CONSOLIDATED FINANCIAL STATEMENTS CE-1 CONSUMERS ENERGY COMPANY SELECTED FINANCIAL INFORMATION
2006 2005 2004 2003 2002 ---- ---- ---- ---- ---- Operating revenue (in millions)........... ($) 5,721 5,232 4,711 4,435 4,169 Earnings from equity method investees (in millions)............................... ($) 1 1 1 42 53 Income (loss) before cumulative effect of change in accounting principle (in millions)............................... ($) 186 (96) 280 196 363 Cumulative effect of change in accounting (in millions)........................... ($) -- -- (1) -- 18 Net income (loss) (in millions)(a)........ ($) 186 (96) 279 196 381 Net income (loss) available to common stockholder (in millions)............... ($) 184 (98) 277 194 335 Cash from operations (in millions)........ ($) 474 640 595 5 760 Capital expenditures, excluding capital lease additions (in millions)........... ($) 646 572 508 486 559 Total assets (in millions)(b)............. ($) 12,845 13,178 12,811 10,745 9,598 Long-term debt, excluding current portion (in millions)(b)........................ ($) 4,127 4,303 4,000 3,583 2,442 Long-term debt -- related parties, excluding current portion (in millions)(c)............................ ($) -- -- 326 506 -- Non-current portion of capital leases and finance lease obligations (in millions)............................... ($) 42 308 315 58 116 Total preferred stock (in millions)....... ($) 44 44 44 44 44 Total Trust Preferred Securities (in millions)(c)............................ ($) -- -- -- -- 490 Number of preferred shareholders at year- end..................................... 1,728 1,823 1,931 2,032 2,132 Book value per common share at year-end... ($) 35.17 33.03 28.68 24.51 22.46 Number of full-time equivalent employees at year-end............................ 8,026 8,114 8,050 7,947 8,311 ELECTRIC STATISTICS Sales (billions of kWh)................. 38 39 38 38 38 Customers (in thousands)................ 1,797 1,789 1,772 1,754 1,734 Average sales rate per kWh.............. (c) 8.46 6.73 6.88 6.91 6.88 GAS UTILITY STATISTICS Sales and transportation deliveries (bcf)................................ 309 350 385 380 376 Customers (in thousands)(d)............. 1,714 1,708 1,691 1,671 1,652 Average sales rate per mcf.............. ($) 10.44 9.61 8.04 6.72 5.67
-------------- (a) See Notes 1 and 3 in the notes to the consolidated financial statements. (b) Until their sale in November 2006 , we were the primary beneficiary of both the MCV Partnership and the FMLP. As a result, we consolidated their assets, liabilities and activities into our consolidated financial statements as of and for the years ended December 31, 2005 and 2004. These partnerships had third party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004. (c) Effective December 31, 2003, Trust Preferred Securities are classified on our consolidated balance sheets as Long-term debt -- related parties. (d) Excludes off-system transportation customers. CE-2 Consumers Energy Company Consumers Energy Company Management's Discussion and Analysis In this MD&A, Consumers Energy, which includes Consumers Energy Company and all of its subsidiaries, is at times referred to in the first person as "we," "our" or "us." EXECUTIVE OVERVIEW Consumers, a subsidiary of CMS Energy, a holding company, is a combination electric and gas utility company serving Michigan's Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers. We manage our business by the nature of services each provides and operate principally in two business segments: electric utility and gas utility. Our electric utility operations include the generation, purchase, distribution, and sale of electricity. Our gas utility operations include the purchase, transportation, storage, distribution, and sale of natural gas. We earn our revenue and generate cash from operations by providing electric and natural gas utility services, electric power generation, gas distribution, transmission, and storage, and other energy related services. Our businesses are affected primarily by: - weather, especially during the normal heating and cooling seasons, - economic conditions, - regulation and regulatory issues, - energy commodity prices, - interest rates, and - our debt credit rating. During the past several years, our business strategy has involved improving our consolidated balance sheet and maintaining focus on our core strength: utility operations and service. We are focused on growing the equity base of our company and have been refinancing our debt to reduce interest rate costs. In 2006, we received $200 million of cash contributions from CMS Energy and we extinguished, through a legal defeasance, $129 million of 9 percent related party notes. In July 2006, we reached an agreement to sell the Palisades nuclear plant to Entergy for $380 million. We also signed a 15-year power purchase agreement with Entergy for 100 percent of the plant's current electric output. We are targeting to close the sale in the second quarter of 2007. When completed, the sale will result in an immediate improvement in our cash flow, a reduction in our nuclear operating and decommissioning risk, and an improvement in our financial flexibility to support other utility investments. We expect to use the proceeds to benefit our customers. We plan to use the cash that we retain from the sale to reduce utility debt. In January 2007, the NRC renewed the Palisades operating license for 20 years, extending it to 2031. Natural gas prices are volatile and have an impact on working capital and cash flow. Although our natural gas costs are recoverable from our utility customers, higher-priced natural gas stored as inventory requires additional liquidity due to the lag in cost recovery. In November 2006, we sold our interests in the MCV Partnership and the FMLP. The sale resulted in a $57 million positive impact on our 2006 cash flow. We used the proceeds to reduce debt. The sale reduced our exposure to volatile natural gas prices. In the future, we will continue to focus on: - investing in our utility system to enable us to meet our customer commitments, comply with increasing environmental performance standards, and maintain adequate supply and capacity, CE-3 Consumers Energy Company - growing earnings, and - managing cash flow issues. As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been hampered by negative developments in Michigan's automotive industry and limited growth in the non-automotive sectors of the state's economy. The return of ROA customer load has offset some of these negative effects. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This is 3 percent of our total distribution load and represents a decrease of 46 percent of ROA load compared to the end of December 2005. FORWARD-LOOKING STATEMENTS AND INFORMATION This Form 10-K and other written and oral statements that we make contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Our intention with the use of words such as "may," "could," "anticipates," "believes," "estimates," "expects," "intends," "plans," and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict and (or) control: - the price of CMS Energy Common Stock, capital and financial market conditions, and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets, including availability of financing to Consumers, CMS Energy, or any of their affiliates and the energy industry, - market perception of the energy industry, Consumers, CMS Energy, or any of their affiliates, - credit ratings of Consumers, CMS Energy, or any of their affiliates, - factors affecting utility and diversified energy operations, such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints, - international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments, - adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions, - potentially adverse regulatory treatment and (or) regulatory lag concerning a number of significant questions presently before the MPSC including: - recovery of Clean Air Act capital and operating costs and other environmental and safety-related expenditures, - power supply and natural gas supply costs when fuel prices are increasing and (or) fluctuating, - timely recognition in rates of additional equity investments in Consumers, - adequate and timely recovery of additional electric and gas rate- based investments, - adequate and timely recovery of higher MISO energy and transmission costs, - recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers, and - sale of the Palisades plant, - the effects on our ability to purchase capacity to serve our customers and fully recover the cost of these purchases, if we exercise our regulatory out rights and the owners of the MCV Facility exercise their right to terminate the MCV PPA, CE-4 Consumers Energy Company - federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of our market- based sales authorizations in wholesale power markets without price restrictions, - energy markets, including availability of capacity and the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity and certain related products due to lower or higher demand, shortages, transportation costs problems, or other developments, - our ability to collect accounts receivable from our customers, - the GAAP requirement that we utilize mark-to-market accounting on certain energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods and could add to earnings volatility, - the effect on our electric utility of the direct and indirect impacts of the continued economic downturn experienced by our automotive and automotive parts manufacturing customers, - potential disruption or interruption of facilities or operations due to accidents or terrorism, and the ability to obtain or maintain insurance coverage for such events, - nuclear power plant performance, operation, decommissioning, policies, procedures, incidents, and regulation, including the availability of spent nuclear fuel storage, - technological developments in energy production, delivery, and usage, - achievement of capital expenditure and operating expense goals, - changes in financial or regulatory accounting principles or policies, - changes in tax laws or new IRS interpretations of existing or past tax laws, - outcome, cost, and other effects of legal and administrative proceedings, settlements, investigations and claims, - disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance and performance bonds, - other business or investment considerations that may be disclosed from time to time in Consumers' or CMS Energy's SEC filings, or in other publicly issued written documents, and - other uncertainties that are difficult to predict, many of which are beyond our control. For additional information regarding these and other uncertainties, see the "Outlook" section included in this MD&A, Note 3, Contingencies, and Part I, Item 1A. Risk Factors. RESULTS OF OPERATIONS NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ----- ------ ----- ---- ------ IN MILLIONS Electric................................... $199 $ 153 $ 46 $ 153 $222 $ (69) Gas........................................ 37 48 (11) 48 71 (23) Other (Includes the MCV Partnership interest)...................... (52) (299) 247 (299) (16) (283) ---- ----- ---- ----- ---- ----- Net Income (Loss) Available to Common Stockholder.............................. $184 $ (98) $282 $ (98) $277 $(375) ==== ===== ==== ===== ==== =====
For 2006, our net income available to our common stockholder was $184 million, compared to a net loss available to our common stockholder of $98 million for 2005. The increase is primarily due to the absence of a 2005 impairment charge to property, plant, and equipment at the MCV Partnership offset partially by charges related to the sale of the MCV Partnership recorded in 2006. For additional details on the impairment and sale of the MCV Facility, see Note 2, Asset Sales and Impairment Charges. The increase also reflects higher net income from our CE-5 Consumers Energy Company electric utility, primarily due to increased revenue resulting from an electric rate order, the expiration of rate caps on our residential customers, and the return of former ROA customers to full-service rates. Partially offsetting these increases are higher operating and maintenance costs at our electric utility, and a reduction in net income from our gas utility. Lower, weather-driven sales at our gas utility exceeded the benefits from lower operating costs and a gas rate increase authorized by the MPSC in November of 2006. Specific changes to net income (loss) available to our common stockholder for 2006 versus 2005 are:
IN MILLIONS ----------- - the net impact of activities associated with the MCV Partnership $ 225 as the absence of a 2005 impairment charge and improved operations in 2006 more than offset the negative effects of mark-to-market activity and charges related to the sale of our interest in the MCV Partnership, - increase in electric delivery revenue primarily due to a 165 December 2005 electric rate order, - increase in earnings due to the expiration of rate caps that, in 37 2005, would not allow us to recover fully our power supply costs from our residential customers, - increase in gas wholesale and retail services and other gas 16 revenue associated with pipeline capacity optimization, - increase in return on electric utility capital expenditures in 14 excess of depreciation base as allowed by the Customer Choice Act, - decrease in income taxes primarily due to an IRS audit 14 settlement, - increase in operating expenses primarily due to higher (101) depreciation and amortization expense, expense, higher electric maintenance expense, and higher customer service expense, - decrease in gas delivery revenue primarily due to lower, (31) weather-driven sales, - increase in operating expenses primarily due to costs related to (29) a planned refueling outage at our Palisades nuclear plant, - increase in interest charges, and (20) - increase in general tax expense, primarily due to higher MSBT (8) expense. ----- Total Change $ 282 =====
For 2005, our net loss available to our common stockholder was $98 million, compared to net income available to our common stockholder of $277 million for 2004. The decrease is primarily due to an impairment charge to property, plant, and equipment at the MCV Partnership to reflect the excess of the carrying value of these assets over their estimated fair value. For additional details on the impairment of the MCV Facility, see Note 2, Asset Sales and Impairment Charges. The decrease also reflects a reduction in net income from our electric utility, as higher operating and maintenance costs exceeded higher, weather-driven sales to our residential customers. Additionally, the decrease reflects a reduction in net income from our gas utility, as higher operating and maintenance costs exceeded the benefits derived from the increase in revenue resulting from the gas rates surcharge authorized by the MPSC in October 2004. Partially offsetting these decreases is an increase in the fair value of certain long-term gas contracts and financial hedges at the MCV Partnership. CE-6 Consumers Energy Company Specific changes to net income (loss) available to our common stockholder for 2005 versus 2004 are:
IN MILLIONS ----------- - decrease in earnings related to our ownership interest in the $(285) MCV Partnership due to an impairment charge to property, plant, and equipment to reflect excess of the carrying value over the estimated fair value of the assets, offset partially by an increase of $100 million from operations, primarily due to an increase in fair value of certain long-term gas contracts and financial hedges, - increase in operating expenses primarily due to higher (136) depreciation and amortization expense, expense, higher pension and benefit expense, and higher underrecovery expense related to the MCV PPA, offset partially by our direct savings from the RCP, - increase in underrecoveries of electric power supply costs due (30) primarily to higher coal costs, as these costs could not be recovered from certain customers due to rate caps that expired at the end of 2005, - decrease in return on electric utility capital expenditures in (20) excess of depreciation base as allowed by the Customer Choice Act, net of related capitalized interest, - increase in electric delivery revenue due to warmer weather and 59 increased surcharge revenue, - decrease in interest charges, 12 - increase in gas delivery revenue due to the MPSC's October 2004 20 final gas rate order and higher miscellaneous income, offset partially by lower deliveries, and - decrease in general tax expense. 5 ----- Total Change $(375) =====
ELECTRIC UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Net income.................................. $199 $153 $ 46 $153 $222 $ (69) ==== ==== ===== ==== ==== ===== REASONS FOR THE CHANGE: Electric deliveries......................... $ 254 $ 91 Power supply costs and related revenue...... 57 (46) Other operating expenses, other income, and non-commodity revenue..................... (236) (131) Regulatory return on capital expenditures... 22 (30) General taxes............................... (7) 6 Interest charges............................ (34) 5 Income taxes................................ (10) 35 Cumulative effect of change in accounting, net of tax expense........................ -- 1 ----- ----- Total change................................ $ 46 $ (69) ===== =====
ELECTRIC DELIVERIES: In 2006, electric delivery revenues increased by $254 million over 2005 despite the fact that electric deliveries to end-use customers were 38.5 billion kWh, a decrease of 0.4 billion kWh or 1.2 percent versus 2005. The decrease in electric deliveries is primarily due to milder summer weather compared to 2005, and resulted in a decrease in electric delivery revenue of $16 million. Despite lower electric deliveries, electric delivery revenue increased primarily due to an electric rate order, increased surcharge revenue, and the return of former ROA CE-7 Consumers Energy Company customers to full-service rates. The impact of these three issues on electric delivery revenue are discussed in the following paragraphs. Electric Rate Order: In December 2005, the MPSC issued an order in our electric rate case. The order increased electric tariff rates and impacted PSCR revenue. As a result of this order, electric delivery revenues increased $160 million in 2006 versus 2005. Surcharge Revenue: On January 1, 2006, we started collecting a surcharge that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This surcharge increased electric delivery revenue by $51 million in 2006 versus 2005. In addition, on January 1, 2006, we started collecting customer choice transition costs from our residential customers that increased electric delivery revenue by $12 million in 2006 versus 2005. Other surcharges decreased electric delivery revenue by $2 million in 2006 versus 2005. ROA Customer Deliveries: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This amount represents a decrease of 46 percent of ROA load compared to the end of December 2005. The return of former ROA customers to full-service rates increased electric revenues $49 million in 2006 versus 2005. For 2005, electric deliveries to end-use customers were 38.9 billion kWh, an increase of 1.3 billion kWh or 3.4 percent versus 2004. The corresponding $68 million increase in electric delivery revenue was primarily due to increased sales to residential customers, reflecting warmer summer weather and increased surcharge revenue from all customers. On July 1, 2004, we started collecting a surcharge to recover costs incurred in the transition to customer choice. This surcharge increased electric delivery revenue by $13 million in 2005 versus 2004. Surcharge revenue related to the recovery of Security Costs and Stranded Costs increased electric delivery revenue by an additional $10 million in 2005 versus 2004. POWER SUPPLY COSTS AND RELATED REVENUE: Rate caps for our residential customers expired on December 31, 2005. In 2006, the absence of rate caps allowed us to record power supply revenue to offset fully our power supply costs. Our ability to recover these power supply costs resulted in an $82 million increase in electric revenue in 2006 versus 2005. Additionally, electric revenue increased $9 million in 2006 versus 2005 primarily due to the return of former special-contract customers to full-service rates in 2006. The return of former special-contract customers to full-service rates allowed us to record power supply revenue to offset fully our power supply costs. Partially offsetting these increases was the absence, in 2006, of deferrals of transmission and nitrogen oxide allowance expenditures related to our capped customers recorded in 2005. These costs were not fully recoverable due to the application of rate caps, so we deferred them for recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the MPSC approved the recovery of these costs. For 2005, deferrals of these costs were $34 million. In 2005, our recovery of power supply costs was capped for our residential customers. The underrecovery of power costs related to these capped customers increased by $76 million versus 2004. Partially offsetting these underrecoveries were benefits from the deferral of transmission and nitrogen oxide allowance expenditures related to our capped customers. To the extent these costs were not fully recoverable due to the application of rate caps, we deferred them for recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the MPSC approved the recovery of these costs. For 2005, deferrals of these costs increased by $30 million versus 2004. OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For 2006, other operating expenses increased $236 million. The increase in other operating expenses reflects higher operating and maintenance, customer service, depreciation and amortization, and pension and benefit expenses. Operating and maintenance expense increased primarily due to costs related to a planned refueling outage at our Palisades nuclear plant, and higher tree trimming and storm restoration costs. Higher customer service expense reflects contributions, beginning in January 2006 pursuant to a December 2005 MPSC order, to a fund that provides energy assistance to low-income customers. Depreciation and amortization expense increased due to higher plant in service and greater amortization of certain regulatory assets. The increase in pension and benefit expense reflects CE-8 Consumers Energy Company changes in actuarial assumptions in 2005, and the latest collective bargaining agreement between the Utility Workers Union of America and Consumers. For 2005, other operating expenses increased $139 million, other income increased $4 million, and non-commodity revenue increased $4 million versus 2004. The increase in other operating expenses reflects higher depreciation and amortization, higher pension and benefit expense, and higher underrecovery expense related to the MCV PPA, offset partially by our direct savings from the RCP. Depreciation and amortization expense increased primarily due to a reduction in 2004 expense to reflect an MPSC order allowing recovery of $57 million of Stranded Costs. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005. In 1992, a liability was established for estimated future underrecoveries of power supply costs under the MCV PPA. In 2004, a portion of the cash underrecoveries continued to reduce this liability until its depletion in December. In 2005, all cash underrecoveries were expensed directly to income. Consequently, the cost associated with the MCV PPA cash underrecoveries increased operating expense $30 million for 2005 versus 2004. Offsetting this increased operating expense were the savings from the RCP approved by the MPSC in January 2005. The RCP allows us to dispatch the MCV Facility on the basis of natural gas prices, which reduces the MCV Facility's annual production of electricity and, as a result, reduces the MCV Facility's consumption of natural gas. The MCV Facility's fuel cost savings are first used to offset the cost of replacement power and fund a renewable energy program. Remaining savings are split between us and the MCV Partnership. Our direct savings were shared 50 percent with customers in 2005 and are being shared 70 percent with customers in 2006 and each year thereafter. Our direct savings, after allocating a portion to customers, was $9 million for 2006 and $32 million for 2005. For 2005, the increase in other income was primarily due to higher interest income on short-term cash investments versus 2004, offset partially by expenses associated with the early retirement of debt. The increase in non-commodity revenue was primarily due to higher transmission services revenue versus 2004. REGULATORY RETURN ON CAPITAL EXPENDITURES: For 2006, the return on capital expenditures in excess of our depreciation base increased income by $22 million versus 2005. The increase reflects the equity return on the regulatory asset authorized by the MPSC's December 2005 order which provided for the recovery of $333 million of Section 10d(4) costs over five years. For 2005, the return on capital expenditures in excess of our depreciation base decreased income by $30 million versus 2004. The decrease reflects a reduction, in 2005, of the equity return on the regulatory asset authorized by the MPSC's December 2005 order. Prior to the MPSC order, the equity return was calculated using a regulatory asset balance that was greater than the amount authorized by the MPSC. GENERAL TAXES: For 2006, the increase in general taxes reflects higher MSBT expense, offset partially by lower property tax expense. For 2005, general taxes decreased primarily due to lower property tax expense, reflecting the use of revised tax tables by several of our taxing authorities and, separately, other property tax refunds. INTEREST CHARGES: For 2006, interest charges increased primarily due to lower capitalized interest and an IRS income tax audit settlement. In 2005, we capitalized $33 million of interest in connection with the MPSC's December 2005 order in our Section 10d(4) Regulatory Asset case. The IRS income tax settlement in 2006 recognized that our taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years. For 2005, interest charges decreased primarily due to higher capitalized interest. In 2005, we capitalized $33 million of interest in connection with the MPSC's December 2005 order in our Section 10d(4) Regulatory Asset case. This benefit was offset partially by higher average debt levels versus 2004. CE-9 Consumers Energy Company INCOME TAXES: For 2006, income taxes increased versus 2005 primarily due to higher earnings by the electric utility, offset partially by the resolution of an IRS income tax audit, which resulted in a $4 million income tax benefit caused by the restoration and utilization of income tax credits. For 2005, income taxes decreased primarily due to lower earnings versus 2004, offset partially by a $2 million increase to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders. CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF TAX EXPENSE: The measurement date for all of our benefit plans is November 30 for 2006, 2005 and 2004, and December 31 for 2003. As a result of the measurement date change, in 2004, we recorded a $1 million, net of tax, cumulative effect adjustment as a decrease to earnings. GAS UTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ---- ------ ---- ---- ------ IN MILLIONS Net income.................................... $37 $48 $(11) $48 $71 $(23) === === ==== === === ==== REASONS FOR THE CHANGE: Gas deliveries................................ $(61) $ (6) Gas rate increase............................. 14 28 Gas wholesale and retail services, other gas revenues, and other income.................. 24 9 Operation and maintenance..................... 7 (49) General taxes and depreciation................ (10) (4) Interest charges.............................. (6) (2) Income taxes.................................. 21 1 ---- ---- Total change.................................. $(11) $(23) ==== ====
GAS DELIVERIES: In 2006, gas delivery revenues decreased by $61 million versus 2005 as gas deliveries, including miscellaneous transportation to end-use customers, were 282 bcf, a decrease of 36 bcf or 11.3 percent. The decrease in gas deliveries was primarily due to warmer weather in 2006 versus 2005 and increased customer conservation efforts in response to higher gas prices. For 2005, gas delivery revenues reflect lower deliveries to our customers versus 2004. Gas deliveries, including miscellaneous transportation to end-use customers, were 318 bcf, a decrease of 2 bcf or 0.7 percent. GAS RATE INCREASE: In May 2006, the MPSC issued an interim gas rate order authorizing an $18 million annual increase to gas tariff rates. In November 2006, the MPSC issued a final order authorizing an annual increase of $81 million. As a result of these orders, gas revenues increased $14 million for 2006 versus 2005. In December 2003, the MPSC issued an interim gas rate order authorizing a $19 million annual increase to gas tariff rates. In October 2004, the MPSC issued a final order authorizing an annual increase of $58 million. As a result of these orders, gas revenues increased $28 million for 2005 versus 2004. GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES, AND OTHER INCOME: For 2006, the increase in gas wholesale and retail services, other gas revenues, and other income primarily reflects higher pipeline revenues and higher pipeline capacity optimization in 2006 versus 2005. For 2005, other gas revenue increased versus 2004 primarily due to higher interest income on short-term cash investments, offset partially by expenses associated with the early retirement of debt. OPERATION AND MAINTENANCE: For 2006, operation and maintenance expenses decreased versus 2005 primarily due to lower operating expenses, offset partially by higher customer service and pension and benefit expenses. Customer service expense increased primarily due to higher uncollectible accounts expense and contributions, beginning in November 2006 pursuant to a November 2006 MPSC order, to a fund that provides energy assistance to low-income customers. The increase in pension and benefit expense reflects changes in CE-10 Consumers Energy Company actuarial assumptions in 2005 and the latest collective bargaining agreement between the Utility Workers Union of America and Consumers. For 2005, operation and maintenance expenses increased primarily due to increases in benefit costs and additional safety, reliability, and customer service expenses versus 2004. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005. GENERAL TAXES AND DEPRECIATION: For 2006, depreciation expense increased versus 2005 primarily due to higher plant in service. The increase in general taxes reflects higher MSBT expense, offset partially by lower property tax expense. For 2005, depreciation expense increased primarily due to higher plant in service versus 2004. The decrease in general taxes is primarily due to lower property tax expense versus 2004. Lower property tax expense in 2005 reflects an increased use of revised tax tables by several of Consumers' taxing authorities, and separately, other property tax refunds. INTEREST CHARGES: For 2006, interest charges increased primarily due to higher interest expense on our GCR overrecovery balance and an IRS income tax audit settlement. The settlement recognized that Consumers' taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years. For 2005, interest charges reflect higher average debt levels versus 2004, offset partially by a lower average rate of interest on our debt. INCOME TAXES: For 2006, income taxes decreased versus 2005 primarily due to lower earnings by the gas utility. Also contributing to the decrease was the absence, in 2006, of the write-off of general business credits that expired in 2005, and the resolution of an IRS income tax audit, which resulted in a $3 million income tax benefit caused by the restoration and utilization of income tax credits. For 2005, income taxes decreased due to lower earnings versus 2004. This decrease was offset by $5 million to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders, and the write-off of general business credits expected to expire in 2005. OTHER NONUTILITY RESULTS OF OPERATIONS
YEARS ENDED DECEMBER 31 2006 2005 CHANGE 2005 2004 CHANGE ----------------------- ---- ----- ------ ----- ---- ------ IN MILLIONS Net loss.......................... $(52) $(299) $247 $(299) $(16) $(283) ==== ===== ==== ===== ==== =====
For 2006, other nonutility operations was a net loss of $52 million, an improvement of $247 million versus 2005. The change is primarily due to a $225 million increase in earnings related to our ownership interest in the MCV Partnership. The increase in MCV Partnership earnings is primarily due to the absence of a 2005 impairment charge to property, plant, and equipment at the MCV Partnership. Partially offseting this increase were charges related to the sale of the MCV Partnership recorded in 2006 and mark-to-market losses on MCV Partnership's long-term gas contracts and associated hedges (which partially reduced gains recorded in 2005). For 2005, other nonutility operations was a net loss of $299 million, a decrease of $283 million versus 2004. The change is primarily due to a $285 million decrease in earnings related to our ownership interest in the MCV Partnership. In September 2005, the MCV Partnership recorded an impairment charge to property, plant, and equipment to reflect the excess of the carrying value of these assets over their estimated fair value. Partially offsetting the impairment charge were mark-to-market gains on the MCV Partnership's long-term gas contracts and associated hedges. CE-11 Consumers Energy Company CRITICAL ACCOUNTING POLICIES The following accounting policies are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies. USE OF ESTIMATES AND ASSUMPTIONS We use estimates and assumptions in preparing our consolidated financial statements that may affect reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, and contingencies. For example, we estimate the rate of return on plan assets and the cost of future health-care benefits to determine our annual pension and other postretirement benefit costs. Actual results may differ from estimated results due to factors such as changes in the regulatory environment, competition, regulatory decisions, and lawsuits. CONTINGENCIES: We are involved in various regulatory and legal proceedings that arise in the ordinary course of our business. We record a liability for contingencies based upon our assessment that a loss is probable and the amount of loss can be reasonably estimated. We use the principles in SFAS No. 5 when recording estimated liabilities for contingencies. We consider many factors in making these assessments, including the history and specifics of each matter. We discuss significant contingencies in the "Outlook" section included in this MD&A. LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. We periodically perform tests of impairment if certain conditions that are other than temporary exist that may indicate the carrying value may not be recoverable. Of our total assets, recorded at $12.845 billion at December 3l, 2006, 58 percent represent long-lived assets and equity method investments that are subject to this type of analysis. We base our evaluations of impairment on such indicators as: - the nature of the assets, - projected future economic benefits, - regulatory and political environments, - state and federal regulatory and political environments, - historical and future cash flow and profitability measurements, and - other external market conditions or factors. We evaluate an asset for impairment if an event occurs or circumstances change in a manner that indicates the recoverability of a long-lived asset should be assessed. We evaluate an asset held-in-use for impairment by calculating the undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. If the undiscounted future cash flows are less than the carrying amount, we recognize an impairment loss. The impairment loss recognized is the amount by which the carrying amount exceeds the fair value. We estimate the fair market value of the asset utilizing the best information available. This information includes quoted market prices, market prices of similar assets, and discounted future cash flow analyses. We record an asset considered held-for-sale at the lower of its carrying amount or fair value, less cost to sell. We assess our ability to recover the carrying amounts of our equity method investments using the fair values of these investments. We determine fair value using valuation methodologies, including discounted cash flows and the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. If the fair value is less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded. Our assessments of fair value using these valuation methodologies represent our best estimates at the time of the reviews and are consistent with our internal planning. The estimates we use can change over time, which could have a material impact on our consolidated financial statements. For additional details on asset impairments, see Note 2, Asset Sales and Impairment Charges. CE-12 Consumers Energy Company ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity. For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate they will require that such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. At December 31, 2006, we had $2.316 billion recorded as regulatory assets and $1.954 billion recorded as regulatory liabilities. ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION FINANCIAL INSTRUMENTS: Debt and equity securities classified as available- for-sale are reported at fair value determined from quoted market prices. Debt and equity securities classified as held-to-maturity are reported at cost. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of AOCI. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary. Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our consolidated earnings or cash flows. DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if certain contracts must be accounted for as derivative instruments. These criteria are complex and significant judgment is often required in applying the criteria to specific contracts. If a contract is a derivative, it is recorded on our consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. For additional details on accounting for derivatives, see Note 5, Financial and Derivative Instruments. To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. Changes in forward prices or volatilities could significantly change the calculated fair value of our derivative contracts. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of our counterparties. The types of contracts we typically classify as derivative instruments are interest rate swaps and gas supply options. The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because: - they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MWh of electricity or bcf of natural gas), - they qualify for the normal purchases and sales exception, or - there is not an active market for the commodity. Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. If an active market for coal develops in the future, some of these contracts may qualify as derivatives and the resulting mark-to-market impact on earnings could be material. Establishment of the Midwest Energy Market: In 2005, the MISO began operating the Midwest Energy Market. As of December 31, 2006, we have determined that, due to the increased liquidity for electricity within the Midwest Energy Market since its inception, it is our best judgment that this market should be considered an active market, as defined by SFAS No. 133. This conclusion does not impact how we account for our electric capacity and CE-13 Consumers Energy Company energy contracts, however, because these contracts qualify for the normal purchases and sales exception and, as a result, are not required to be marked- to-market. Derivatives Associated with the MCV Partnership: In November 2006, we sold our interest in the MCV Partnership. In conjunction with that sale, our interest in all of the MCV Partnership's long-term gas contracts and related futures, options, and swaps was sold. Before the sale, we accounted for certain long-term gas contracts and all of the related futures, options, and swaps as derivatives. Certain of these derivatives, specifically the long-term gas contracts, the options, and a portion of the futures and swaps, did not qualify for cash flow hedge accounting treatment. As such, we recorded the mark-to-market gains and losses from these derivatives in earnings each quarter. The gains and losses recorded in earnings during 2006, through the date of the sale, were as follows:
2006 ----------------------------------------- FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL ------- ------- ------- ------- ----- IN MILLIONS Long-term gas contracts........................ $(111) $(34) $(16) $10 $(151) Related futures, options, and swaps............ (45) (8) (12) 12 (53) ----- ---- ---- --- ----- Total.......................................... $(156) $(42) $(28) $22 $(204) ===== ==== ==== === =====
These derivatives incurred significant mark-to-market losses in the first three quarters of the year, due to the decrease in natural gas prices during that time. In the fourth quarter (through the date of the sale), natural gas prices increased, resulting in a mark-to-market gain. The overall net losses, shown before consideration of tax effects and minority interest, are included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss). The remaining futures and swaps held by the MCV Partnership did qualify for cash flow hedge accounting. As such, we recorded our proportionate share of the mark-to-market gains and losses from these derivatives in AOCI each quarter. As of the date of the sale, we had accumulated a net gain of $30 million, net of tax and minority interest, in AOCI representing our proportionate share of the mark-to-market gains from these cash flow hedges. After the sale, this amount was reclassified to and recognized in earnings as a reduction of the total loss on the sale in our Consolidated Statements of Income (Loss). As a result of the sale, we no longer consolidate the MCV Partnership. Accordingly, we no longer record the fair value of the long-term gas contracts and related futures, options, and swaps on our Consolidated Balance Sheets and are not required to record gains or losses related to changes in the fair value of these contracts in earnings or AOCI. For additional details on the sale of our interest in the MCV Partnership, see the "Other Electric Business Uncertainties -- The MCV Partnership" section in this MD&A and Note 2, Asset Sales and Impairment Charges. MARKET RISK INFORMATION: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, and equity security prices. We may use various contracts to manage these risks, including options, swaps, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of both: - an executive oversight committee consisting of senior management representatives, and - a risk committee consisting of business unit managers. Our intention is to limit our exposure to risk from interest rate and commodity price volatility. These contracts contain credit risk, which is the risk that counterparties, primarily financial institutions and energy marketers, will fail to perform their contractual obligations. We reduce this risk through established credit policies, which include performing financial credit reviews of our counterparties. We determine our counterparties' credit quality using a number of factors, including credit ratings, disclosed financial condition, and collateral requirements. If terms permit, we use standard agreements that allow us to net positive and negative exposures associated with the same counterparty. Based on these policies and our current exposures, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance. CE-14 Consumers Energy Company The following risk sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical adverse change in market rates or prices of 10 percent. Changes in excess of the amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift used for the analyses. Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital. Interest Rate Risk Sensitivity Analysis (assuming an increase in market interest rates of 10 percent):
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Variable-rate financing -- before tax annual earnings exposure.... $ 3 $ 3 Fixed-rate financing -- potential REDUCTION in fair value(a)...... 134 149
-------------- (a) Fair value reduction could only be realized if we repurchased all of our fixed-rate financing. Commodity Price Risk: Operating in the energy industry, we are exposed to commodity price risk, which arises from fluctuations in the price of electricity, natural gas, coal, and other commodities. Commodity prices are influenced by a number of factors, including weather, changes in supply and demand, and liquidity of commodity markets. In order to manage commodity price risk, we enter into various non-trading derivative contracts, such as gas supply call and put options. For additional details on these contracts, see Note 5, Financial and Derivative Instruments. Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market prices of 10 percent):
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Potential REDUCTION in fair value: Gas supply option contracts........................................ $-- $ 1 Fixed fuel price contracts(a)...................................... 1 -- Derivative contracts associated with the MCV Partnership: Long-term gas contracts(b)....................................... -- 39 Gas futures, options, and swaps(b)............................... -- 48
-------------- (a) We have entered into two contracts that, from January to September 2007, will fix the prices we pay for gasoline and diesel fuel used in our fleet vehicles and equipment. These contracts are derivatives with an immaterial fair value at December 31, 2006. (b) The potential reduction in fair value for the MCV Partnership's long- term gas contracts and gas futures, options, and swaps decreased to $0 as a result of the sale of our interest in the MCV Partnership. In conjunction with that sale, our interest in these contracts was also sold and, as a result, we no longer record the fair value of these contracts on our Consolidated Balance Sheets at December 31, 2006. Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available- for-sale investments. Investment Securities Price Risk Sensitivity Analysis (assuming an adverse change in market prices of 10 percent):
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Potential REDUCTION in fair value of available-for-sale equity securities (SERP investments and investment in CMS Energy common stock)........................................................... $6 $6
CE-15 Consumers Energy Company We maintain trust funds, as required by the NRC, for the purpose of funding certain costs of nuclear plant decommissioning. These funds are invested primarily in equity securities, fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are recorded at fair value on our Consolidated Balance Sheets. These investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear plant decommissioning recognizes that costs are recovered through our electric rates, fluctuations in equity prices or interest rates do not affect our consolidated earnings or cash flows. For additional details on market risk and derivative activities, see Note 5, Financial and Derivative Instruments. For additional details on nuclear plant decommissioning at Big Rock and Palisades, see the "Other Electric Business Uncertainties -- Nuclear Matters" section included in this MD&A. ACCOUNTING FOR PENSION AND OPEB Pension: We have external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. On September 1, 2005, the defined benefit Pension Plan was closed to new participants and we implemented the DCCP, which provides an employer contribution of 5 percent of base pay to the existing Employees' Savings Plan. An employee contribution is not required to receive the plan's employer cash contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Previous cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. 401(k): We resumed the employer's match in CMS Energy Common Stock in our 401(k) Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages. Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be an investment option available for new investments in the 401(k) Savings Plan and the employer's match will no longer be in CMS Energy Common Stock. Participants will have the opportunity to reallocate investments in CMS Energy Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment options. At February 20, 2007, there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy Stock Fund. OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. In accordance with SFAS No. 158, we record liabilities for pension and OPEB on our consolidated balance sheet at the present value of their future obligations, net of any plan assets. We use SFAS No. 87 to account for pension expense and SFAS No. 106 to account for other postretirement benefit expense. The calculation of the liabilities and associated expenses requires the expertise of actuaries, and require many assumptions, including: - life expectancies, - present-value discount rates, - expected long-term rate of return on plan assets, - rate of compensation increases, and - anticipated health care costs. A change in these assumptions could change significantly our recorded liabilities and associated expenses. CE-16 Consumers Energy Company The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
EXPECTED COSTS PENSION COST OPEB COST CONTRIBUTIONS -------------- ------------ --------- ------------- IN MILLIONS 2007.............................................. $103 $45 $153 2008.............................................. 99 42 50 2009.............................................. 106 40 50
Actual future pension cost and contributions will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Pension Plan. Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.25 percent to 8.00 percent) would increase estimated pension cost for 2007 by $2 million. Lowering the discount rate by 0.25 percent (from 5.65 percent to 5.40 percent) would increase estimated pension cost for 2007 by $1 million. For additional details on postretirement benefits, see Note 6, Retirement Benefits. ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS SFAS No. 143, as clarified by FASB Interpretation No. 47, requires companies to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. As required by SFAS No. 71, we accounted for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle. The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, gas transmission and electric and gas distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. In addition, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates. For additional details see Note 3, Contingencies, "Other Electric Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase Agreement," and Note 7, Asset Retirement Obligations. ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS The MPSC and the FERC regulate the recovery of costs to decommission, or remove from service, our Big Rock and Palisades nuclear plants. Our decommissioning cost estimates for the Big Rock and Palisades plants assume: - each plant site will be restored to conform to the adjacent landscape, - all contaminated equipment and material will be removed and disposed of in a licensed burial facility, and - the site will be released for unrestricted use. Independent contractors with expertise in decommissioning assist us in developing decommissioning cost estimates. We use various inflation rates for labor, non-labor, and contaminated equipment disposal costs to escalate these cost estimates to the future decommissioning cost. A portion of future decommissioning cost will result from the failure of the DOE to remove spent nuclear fuel from the sites, as required by the Nuclear Waste Policy Act of 1982. CE-17 Consumers Energy Company We have external trust funds to finance the decommissioning of both plants. We record the trust fund balances as a non-current asset on our Consolidated Balance Sheets. The decommissioning trust funds include equities and fixed- income investments. Equities are converted to fixed-income investments during decommissioning, and fixed-income investments are converted to cash as needed. The costs of decommissioning these sites and the adequacy of the trust funds could be affected by: - variances from expected trust earnings, - a lower recovery of costs from the DOE and lower rate recovery from customers, and - changes in decommissioning technology, regulations, estimates, or assumptions. Based on current projections, the current level of funds provided by the trusts is not adequate to fund fully the decommissioning of Big Rock. This is due in part to the DOE's failure to accept the spent nuclear fuel on schedule and lower returns on the trust funds. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation. For additional details, see Note 3, Contingencies, "Other Electric Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase Agreement," "Nuclear Plant Decommissioning" and "Nuclear Matters," and Note 7, Asset Retirement Obligations. RELATED PARTY TRANSACTIONS We enter into a number of significant transactions with related parties. These transactions include: - issuance of trust preferred securities with Consumers' affiliated companies, - purchase and sale of electricity from and to Enterprises, - purchase of gas transportation from CMS Bay Area Pipeline, L.L.C., - payment of parent company overhead costs to CMS Energy, and - investment in CMS Energy Common Stock. Transactions involving CMS Energy and its affiliates generally are based on regulated prices, market prices, or competitive bidding. Transactions involving the power supply purchases from certain affiliates of Enterprises are based upon avoided costs under PURPA and competitive bidding. The payment of parent company overhead costs is based on the use of accepted industry allocation methodologies. For additional details on related party transactions, see Note 1, Corporate Structure and Accounting Policies, "Related Party Transactions." CAPITAL RESOURCES AND LIQUIDITY Factors affecting our liquidity and capital requirements are: - results of operations, - capital expenditures, - energy commodity and transportation costs, - contractual obligations, - regulatory decisions, - debt maturities, - credit ratings, - working capital needs, and - collateral requirements. During the summer months, we purchase natural gas and store it for resale primarily during the winter heating season. Although our prudent natural gas costs are recoverable from our customers, the amount paid for natural gas stored as inventory requires additional liquidity due to the lag in cost recovery. We have credit agreements with our commodity suppliers containing terms that have previously resulted in margin calls. While we currently have no CE-18 Consumers Energy Company outstanding margin calls associated with our natural gas purchases, they may be required if agency ratings are lowered or if market conditions become unfavorable relative to our obligations to those parties. Our current financial plan includes controlling operating expenses and capital expenditures and evaluating market conditions for financing opportunities, if needed. We believe the following items will be sufficient to meet our liquidity needs: - our current level of cash and revolving credit facilities, - our anticipated cash flows from operating and investing activities, and - our ability to access secured and unsecured borrowing capacity in the capital markets, if necessary. In the second quarter of 2006, Moody's revised our credit rating outlook to stable from negative. In the third quarter of 2006, Moody's upgraded our credit ratings. CASH POSITION, INVESTING, AND FINANCING Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2006, $94 million consolidated cash was on hand, which includes $57 million of restricted cash. We had no cash from entities consolidated pursuant to FASB Interpretation No. 46(R) due to the sale of the MCV Partnership and the FMLP. SUMMARY OF CASH FLOWS:
2006 2005 2004 ----- ----- ----- IN MILLIONS Net cash provided by (used in): Operating activities..................................... $ 474 $ 640 $ 595 Investing activities..................................... (673) (662) (517) ----- ----- ----- Net cash provided by (used in) operating and investing activities............................................... (199) (22) 78 Financing activities..................................... (180) 267 (127) ----- ----- ----- Net Increase (Decrease) in Cash and Cash Equivalents....... $(379) $ 245 $ (49) ===== ===== =====
OPERATING ACTIVITIES: 2006: Net cash provided by operating activities was $474 million, a decrease of $166 million versus 2005. This was the result of decreases in the MCV Partnership gas supplier funds on deposit, accounts payable and income tax payments to the parent. These changes were offset partially by a decrease in accounts receivable and reduced inventory purchases. The decrease in the MCV Partnership gas supplier funds on deposit was the result of refunds to suppliers from decreased exposure due to declining gas prices in 2006. The decrease in accounts payable was mainly due to payments for higher-priced gas that were accrued at December 31, 2005. The decrease in accounts receivable was primarily due to the collection of receivables in 2006 reflecting higher gas prices billed during the latter part of 2005 and reduced billings in the latter part of 2006 due to milder weather. 2005: Net cash provided by operating activities was $640 million, an increase of $45 million versus 2004. Cash provided by operations resulted primarily from a decrease in prepaid gas margin call costs, an increase in tax liabilities related to a recent IRS ruling regarding the "simplified service cost" method of tax accounting, the positive effect of rising gas prices on accounts payable and the MCV Partnership gas supplier funds on deposit, and other timing differences. These increases were offset partially by the negative effect of rising gas prices on accounts receivable and inventories. INVESTING ACTIVITIES: 2006: Net cash used in investing activities was $673 million, an increase of $11 million versus 2005. This increase was due to cash relinquished from the sale of assets, an increase in capital expenditures and cost to retire property and a decrease in net proceeds from investments. These changes were partially offset by a decrease in CE-19 Consumers Energy Company restricted cash and restricted short-term investments. Cash restricted in 2005 was released in February 2006, which we used to extinguish long-term debt -- related parties. 2005: Net cash used in investing activities was $662 million, an increase of $145 million versus 2004. This increase was primarily due to an increase in restricted cash and restricted short-term investments of $159 million. The increase in restricted cash and restricted short-term investments was due to a deposit made with a trustee for extinguishing the current portion of long-term debt -- related parties. FINANCING ACTIVITIES: 2006: Net cash used in financing activities was $180 million, an increase of $447 million versus 2005. This increase was due to a decrease of $500 million in contributions from the parent and an increase in net retirement of long-term debt. These changes were partially offset by a decrease in common stock dividends payments of $130 million. 2005: Net cash provided by financing activities was $267 million, an increase of $394 million versus 2004. This increase was due to an increase of $450 million in contributions from the parent and an increase in cash due to lower payments on borrowings of $16 million, offset by an increase in common stock dividends payments of $87 million. For additional details on long-term debt activity, see Note 4, Financings and Capitalization. OBLIGATIONS AND COMMITMENTS CONTRACTUAL OBLIGATIONS: The following table summarizes our contractual cash obligations for each of the periods presented. The table shows the timing and effect that such obligations are expected to have on our liquidity and cash flow in future periods. The table excludes all amounts classified as current liabilities on our Consolidated Balance Sheets, other than the current portion of long-term debt and capital and finance leases.
PAYMENTS DUE ------------------------------------------------------- CONTRACTUAL OBLIGATIONS LESS THAN ONE TO THREE TO MORE THAN AT DECEMBER 31, 2006 TOTAL ONE YEAR THREE YEARS FIVE YEARS FIVE YEARS ----------------------- ----- --------- ----------- ---------- ---------- IN MILLIONS Long-term debt(a)....................... $ 4,158 $ 31 $ 825 $ 380 $ 2,922 Interest payments on long-term debt(b).. 1,904 209 375 314 1,006 Capital leases(c)....................... 55 13 14 10 18 Interest payments on capital leases(d).. 26 -- 9 6 11 Operating leases(e)..................... 159 23 41 34 61 Purchase obligations(f)................. 16,334 2,118 2,109 1,661 10,446 Purchase obligations -- related parties(f)............................ 1,506 74 148 148 1,136 ------- ------ ------ ------ ------- Total contractual obligations......... $24,142 $2,468 $3,521 $2,553 $15,600 ======= ====== ====== ====== =======
-------------- (a) Principal amounts due on outstanding debt obligations, current and long- term, at December 31, 2006. For additional details on long-term debt, see Note 4, Financings and Capitalization. (b) Currently scheduled interest payments on both variable and fixed rate long-term debt, current and long-term. Variable are based on contractual rates in effect at December 31, 2006. (c) Minimum lease payments under our capital leases, comprised mainly of leased service vehicles, leased office furniture, and certain power purchase agreements. (d) Imputed interest in the capital leases. (e) Minimum noncancelable lease payments under our leases of railroad cars, certain vehicles, and miscellaneous office buildings and equipment, which are accounted for as operating leases. (f) Long-term contracts for purchase of commodities and services. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. These commodities and services include: CE-20 Consumers Energy Company - natural gas and associated transportation, - electricity, and - coal and associated transportation. Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $46 million per month during 2007. If a plant is not available to deliver electricity, we are not obligated to make these payments to the plant for that period of time. For additional details on power supply costs, see "Electric Utility Results of Operations" within this MD&A and Note 3, Contingencies, "Electric Rate Matters -- Power Supply Costs." REVOLVING CREDIT FACILITIES: At December 31, 2006, we had $742 million available in secured revolving credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. For additional details on revolving credit facilities, see Note 4, Financings and Capitalization. OFF-BALANCE SHEET ARRANGEMENTS: We enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, letters of credit and surety bonds. We enter into agreements containing indemnifications standard in the industry and indemnifications specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually agreements to reimburse other companies if those companies incur losses due to third-party claims or breach of contract terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a third-party. Letters of credit substitute the bank's credit for ours and reduce credit risk for the third-party beneficiary. We monitor these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. For additional details on these arrangements, see Note 3, Contingencies, "Other Contingencies -- FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we may sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for securitized financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see Note 4, Financings and Capitalization. DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4, Financings and Capitalization. CAPITAL EXPENDITURES: We estimate that we will make the following capital expenditures, including new lease commitments, by expenditure type and by business segments during 2007 through 2009. We prepare these estimates for planning purposes. Periodically, we review these estimates and may revise them due to a number of factors including environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.
YEARS ENDING DECEMBER 31 2007 2008 2009 ------------------------ ---- ---- ---- IN MILLIONS Construction................................................. $429 $351 $361 Clean Air(a)................................................. 90 29 60 Cost of Removal.............................................. 49 50 43 New Customers................................................ 108 112 109 Other(b)..................................................... 106 161 156 ---- ---- ---- $782 $703 $729 ==== ==== ==== Electric utility operations(a)(b)............................ $618 $487 $455 Gas utility operations(b).................................... 164 216 274 ---- ---- ---- $782 $703 $729 ==== ==== ====
CE-21 Consumers Energy Company -------------- (a) These amounts include estimates for capital expenditures that may be required by revisions to the Clean Air Act's national air quality standards. (b) These amounts include estimates for capital expenditures related to information technology projects, facility improvements, and vehicle leasing. OUTLOOK CORPORATE OUTLOOK In November 2006, we announced a reorganization of the company to improve operating efficiency, reliability, and customer service. The new organization will streamline operations and will allow us to serve our customers better and more efficiently. ELECTRIC BUSINESS OUTLOOK GROWTH: Temperatures in the summer of 2006 were higher than historical averages yet lower than in the summer of 2005. Industrial activity declined during 2006 compared with 2005. These factors resulted in a decline of one percent in annual electric deliveries, excluding transactions with other wholesale market participants and other electric utilities. In 2007, we project electric deliveries to grow less than one-half of one percent compared to the levels experienced in 2006. This short-term outlook for 2007 assumes a small decline in industrial economic activity and normal weather conditions throughout the year. Over the next five years, we expect electric deliveries to grow at an average rate of less than 1.5 percent a year. However, this is dependent on a modestly growing customer base and a stabilizing Michigan economy after 2007. This growth rate includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. This growth rate reflects a long-range expected trend of growth. Growth from year to year may vary from this trend due to customer response to the following: - fluctuations in weather conditions and - changes in economic conditions, including utilization and expansion or contraction of manufacturing facilities. ELECTRIC RESERVE MARGIN: We are planning for a reserve margin of approximately 11 percent for summer 2007, or supply resources equal to 111 percent of projected firm summer peak load. Of the 2007 supply resources target of 111 percent, we expect 96 percent to come from our electric generating plants and long-term power purchase contracts, and 15 percent to come from other contractual arrangements. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2007 through 2010. As a result, we recognized an asset of $62 million for unexpired capacity and energy contracts at December 31, 2006. Upon the completion of the sale of the Palisades plant, the 15-year power purchase agreement with Entergy for 100 percent of the plant's current electric output will offset the reduction in the owned capacity represented by the Palisades plant. The MCV PPA is unaffected by the sale of our interest in the MCV Partnership. After September 15, 2007, we expect to exercise the regulatory out provision in the MCV PPA. If we are successful, the MCV Partnership has the right to terminate the MCV PPA, which could affect our reserve margin status. The MCV PPA represents 13 percent of our 2007 supply resources target. ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission service to us, increased substantially the transmission rates it charged us in 2006. The revenue collected by METC under those rates is subject to refund pending a FERC ruling. In January 2007, a settlement agreement among the parties was filed with the FERC resolving all issues associated with the rates METC charged us in 2006. This settlement, if approved by the FERC, will result in a refund of 2006 transmission charges of $18 million and a corresponding reduction of our power supply costs. In August 2006, the MPSC approved recovery of the increased METC electric transmission costs included in our 2006 PSCR plan. Due to the delay in recovery, we were unable to collect these increased costs in a timely manner CE-22 Consumers Energy Company and our cash flows from electric utility operations were affected negatively. For additional details, see Note 3, Contingencies, "Electric Rate Matters -- Power Supply Costs." CUSTOMER REVENUE OUTLOOK: Our electric utility customer base includes a mix of residential, commercial, and diversified industrial customers. In 2006, Michigan's automotive industry experienced negative developments resulting in manufacturing facility closures and restructurings. Our electric utility operations are not dependent upon a single customer, or even a few customers, and customers in the automotive sector constitute five percent of our total 2006 electric revenue. In addition, returning former ROA industrial customers benefit our electric utility revenue. However, we cannot predict the impact of current or possible future restructuring plans or possible future actions by our industrial customers. 21ST CENTURY ENERGY PLAN: In January 2006, the MPSC Staff issued a report on future electric capacity in the state of Michigan. The report indicated that existing generation resources are adequate in the short term, but could be insufficient to maintain reliability standards by 2009. The MPSC Staff recommended a review process for proposed new power plants. In January 2007, the chairman of the MPSC expanded on the capacity need work conducted by the MPSC Staff and proposed three major policy initiatives to the governor of Michigan. The initiatives involve the use of more renewable energy resources by all load- serving entities such as Consumers, the creation of an energy efficiency program, and a procedure for reviewing proposals to construct new generation facilities. The January 2007 proposal indicated that Michigan needs new baseload generation by 2015 and recommends regulatory measures to make it easier to predict customer demand and revenues. The proposed initiatives will require changes to current legislation. We will continue to participate as the MPSC, legislature, and other stakeholders addresses future electric capacity needs. ELECTRIC BUSINESS UNCERTAINTIES Several electric business trends or uncertainties may affect our financial condition and future results of operations. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric operations. ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates. Clean Air Act: Compliance with the federal Clean Air Act and resulting regulations continues to be a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $835 million. These expenditures include installing selective catalytic reduction control technology on four of our coal-fired electric generating units. The key assumptions in the capital expenditure estimate include: - construction commodity prices, especially construction material and labor, - project completion schedules, - cost escalation factor used to estimate future years' costs, and - an AFUDC capitalization rate. Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 7.8 percent. As of December 2006, we have incurred $688 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $147 million of capital expenditures will be made in 2007 through 2011. In addition to modifying coal-fired electric generating plants, our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $3 million per year, which we expect to recover from our customers through the PSCR process. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the coal-fired electric generating plants emit nitrogen oxide. CE-23 Consumers Energy Company Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. We plan to meet this rule by year-round operation of our selective catalytic reduction control technology units and installation of flue gas desulfurization scrubbers at an estimated total cost of $955 million, to be incurred by 2014. The rule may also require us to purchase additional nitrogen oxide allowances beginning in 2009. Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.4 percent. We will need to acquire additional sulfur dioxide emission allowances for an average annual cost of $21 million per year for the years 2011 through 2014. Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal- fired electric generating plants by 2010 and further reductions by 2018. Based on current technology, we anticipate our capital costs for mercury emissions reductions required by Phase I of the Clean Air Mercury Rule to be less than $50 million and expect these reductions to be implemented by, 2010. Phase II requirements of the Clean Air Mercury Rule are not yet known and a cost estimate has not been determined. In April 2006, Michigan's governor announced a plan that would result in mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ on the details of these rules. We will develop a cost estimate when the details of these rules are determined. Greenhouse gases: Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, including carbon dioxide. We cannot predict whether any of these proposals will be enacted, or the specific requirements of any of these proposals and their effect on our future operations and financial results. In addition, the U.S. Supreme Court has agreed to hear a case claiming that the EPA is required by the Clean Air Act to consider regulating carbon dioxide emissions from automobiles. The EPA asserts that it lacks authority to regulate carbon dioxide emissions. If the Supreme Court finds that the EPA has authority to regulate carbon dioxide emissions in this case, it could result in new federal carbon dioxide regulations for other industries, including the utility industry. To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. We cannot estimate the potential effect of federal or state level greenhouse gas policy on our future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, we will continue to monitor greenhouse gas policy developments and assess and respond to their potential implications on our business operations. Water: In March 2004, the EPA issued rules that govern electric generating plant cooling water intake systems. The rules require significant reduction in fish killed by operating equipment. EPA compliance options in the rule were challenged in court. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The court's ruling is expected to increase significantly the cost of complying with this rule. However, the cost to comply will not be known until the EPA's reconsideration is complete. At this time, the EPA has not established a schedule to address the court decision. For additional details on electric environmental matters, see Note 3, Contingencies, "Electric Contingencies -- Electric Environmental Matters." COMPETITION AND REGULATORY RESTRUCTURING: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers. This is 3 percent of our total distribution load and represents a decrease of 46 percent of ROA load compared to the end of December 2005. In prior orders, the MPSC approved recovery of Stranded Costs incurred from 2002 through 2003 through a surcharge assessed to ROA customers. It is difficult to predict future ROA customer trends and their impact on the timely recovery of our Stranded Costs. ELECTRIC RATE CASE: We expect to file an electric rate case in March 2007. CE-24 Consumers Energy Company For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, "Electric Rate Matters." OTHER ELECTRIC BUSINESS UNCERTAINTIES THE MCV PARTNERSHIP: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990. Sale of our Interest in the MCV Partnership and the FMLP: In November 2006, we sold 100 percent of our ownership interest in MCV GP II (the successor of CMS Midland, Inc.) and 100 percent of our ownership interest in the stock of CMS Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments for $60.5 million. These Consumers subsidiaries held our interests in the MCV Partnership and the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments, to pay $85 million, subject to certain conditions and reimbursement rights, if Dow terminates an agreement under which the MCV Partnership provides it power and steam. The purchaser secured their reimbursement obligation with an irrevocable letter of credit of up to $85 million. The MCV PPA and the associated customer rates are unaffected by the sale. The transaction resulted in a net after-tax loss of $41 million, which includes the reversal of $30 million, into earnings, of certain cumulative amounts of the MCV Partnership derivative fair value changes that we accounted for in AOCI. For additional details on the sale of our interests in the MCV Partnership and the FMLP, see Note 2, Asset Sales and Impairment Charges and Note 5, Financial and Derivative Instruments, "Derivative Contracts Associated with the MCV Partnership." Underrecoveries related to the MCV PPA: The cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we incurred cash underrecoveries of capacity and fixed energy payments of $57 million in 2006 and we estimate cash underrecoveries of $39 million in 2007. However, we use the direct savings from the RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. This action would eliminate our underrecoveries of capacity and fixed energy payments. The MCV Partnership has notified us that it takes issue with our intended exercise of the regulatory out provision after September 15, 2007. We believe that the provision is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out provision, the MCV Partnership has the right to terminate the MCV PPA. If the MCV Partnership terminates the MCV PPA, we would seek to replace the lost capacity to maintain an adequate electric reserve margin. This could involve entering into a new PPA and (or) entering into electric capacity contracts on the open market. We cannot predict our ability to enter into such contracts at a reasonable price. We are also unable to predict regulatory approval of the terms and conditions of such contracts, or that the MPSC would allow full recovery of our incurred costs. For additional details on the MCV Partnership, see Note 3, Contingencies, "Other Electric Contingencies -- The MCV PPA." NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006, we reached an agreement to sell Palisades to Entergy for $380 million and pay Entergy $30 million to assume ownership and responsibility for the Big Rock Independent Spent Fuel Storage Installation (ISFSI). Under the agreement, if the transaction does not close by March 1, 2007, there is a reduction in the purchase price of approximately $80,000 per day, with additional costs if the transaction does not close by June 1, 2007. Based on the MPSC's published schedule for the contested case proceedings regarding this transaction, we target to close on the transaction in the second quarter of 2007. We estimate that the Palisades sale will result in a $31 million premium above the Palisades asset values at the anticipated closing date after accounting for estimated sales-related costs. We expect that this premium will benefit our customers. Entergy will assume responsibility for the future decommissioning of the plant and for storage and disposal of spent nuclear fuel located at the Palisades and the Big Rock ISFSI sites. At the anticipated date of close, we estimate decommissioning trust assets to be $605 million. We will retain $205 million of these funds at the time of close and will be entitled to receive a return of an additional $147 million, pending either a favorable federal tax ruling CE-25 Consumers Energy Company regarding the release of the funds or, if no such ruling is issued, after decommissioning of the Palisades site is complete. These estimates fluctuate based on existing market conditions. The disposition of the retained and receivable nuclear decommissioning funds is subject to regulatory approval. We expect to use the proceeds to benefit our customers. We plan to use the cash that we retain from the sale to reduce utility debt. As part of the transaction, Entergy will sell us 100 percent of the plant's output up to its current capacity of 798 MW under a 15-year power purchase agreement. The sale is subject to various regulatory approvals, including the MPSC's approval of the power purchase agreement and the NRC's approval of the transfer of the operating license to Entergy and other related matters. In February 2007, the FERC issued an order approving the sale of power to us under the power purchase agreement and granted other related approvals, with what we believe are minor exceptions and conditions that we believe can be adequately accepted. In October 2006, the Federal Trade Commission issued a notice that neither it nor the DOJ's Antitrust Division plan to take enforcement action on the sale. The final purchase price will be subject to various closing adjustments such as working capital and capital expenditure adjustments, adjustments for nuclear fuel usage and inventory, and the date of closing. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur. We have notified the NMC that we plan to terminate the NMC's operation of Palisades, if the sale is completed, which would require us to pay the NMC an estimated $12 million. Due to the regulatory approvals pending, we have not recorded this contingent obligation. For additional details on sale of Palisades and the Big Rock ISFSI, see Note 3, Contingencies, "Other Electric Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase Agreement." Big Rock: Dismantlement and decommissioning of the Big Rock Plant was completed in August 2006. In November 2006, we requested the NRC to release approximately 435 acres from the terms of our operating license. In January 2007, the NRC approved our request to release the 435 acres for unrestricted public use. An area of approximately 107 acres including the Big Rock ISFSI, where eight casks loaded with spent fuel and other high-level radioactive material are stored, is part of the sale of nuclear assets as previously described. Palisades: The amount of spent nuclear fuel at Palisades exceeds the plant's temporary onsite wet storage pool capacity. We are using dry casks for temporary onsite dry storage to supplement the wet storage pool capacity. Palisades' original license from the NRC was scheduled to expire in 2011. In March 2005, the NMC, which operates the Palisades plant, applied for a 20- year license renewal for the plant on behalf of Consumers. In January 2007, the NRC renewed the Palisades operating license for 20 years, extending it to 2031. For additional details on nuclear plant decommissioning at Big Rock and Palisades, see Note 3, Contingencies, "Other Electric Contingencies -- Nuclear Plant Decommissioning." GAS BUSINESS OUTLOOK GROWTH: In 2007, we project gas deliveries will decline slightly, on a weather-adjusted basis, from 2006 levels due to continuing conservation and overall economic conditions in the state of Michigan. Over the next five years, we expect gas deliveries to decline by less than one-half of one percent annually. Actual gas deliveries in future periods may be affected by: - fluctuations in weather conditions, - use by independent power producers, - competition in sales and delivery, - changes in gas commodity prices, - Michigan economic conditions, - the price of competing energy sources or fuels, - gas consumption per customer, and - improvements in gas appliance efficiency. CE-26 Consumers Energy Company GAS BUSINESS UNCERTAINTIES Several gas business trends or uncertainties may affect our future financial results and financial condition. These trends or uncertainties could have a material impact on future revenues or income from gas operations. GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 3, Contingencies, "Gas Contingencies -- Gas Environmental Matters." GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudency in annual plan and reconciliation proceedings. For additional details on gas cost recovery, see Note 3, Contingencies, "Gas Rate Matters -- Gas Cost Recovery." GAS DEPRECIATION: We are required to file our next gas depreciation case with the MPSC within 90 days after the MPSC issuance of a final order in the pending case related to ARO accounting. We cannot predict when the MPSC will issue a final order in the ARO accounting case. If a final order in our next gas depreciation case is not issued concurrently with a final order in a general gas rate case, the MPSC may incorporate the results of the depreciation case into general gas rates through use of a surcharge mechanism (which may be either positive or negative). 2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity along with an $88 million annual increase in our gas delivery and transportation rates. We have proposed the use of a Revenue Decoupling and Conservation Incentive Mechanism for residential and general service rate classes to help assure a reasonable opportunity to recover costs that do not fluctuate with volumetric changes. OTHER OUTLOOK RULES REGARDING BILLING PRACTICES: In December 2006, the MPSC issued proposed rule changes to residential customer billing standards and practices. These changes, if adopted, would provide additional protection to low-income customers during the winter heating season that will be defined as November 1 through March 31, extend the time between billing date and due date from 17 days to 22 days, and eliminate estimated metering readings unless actual readings are not feasible. We are presently evaluating the impacts of these proposed rules and are working with other Michigan utilities in providing comments to the MPSC regarding the proposed rule changes. LITIGATION AND REGULATORY INVESTIGATION: CMS Energy is the subject of various investigations as a result of round-trip trading transactions by CMS MST, including an investigation by the DOJ. For additional details regarding this investigation and litigation, see Note 3, Contingencies. PENSION REFORM: In August 2006, the President signed into law the Pension Protection Act of 2006. The bill reforms the funding rules for employer-provided pension plans, effective for plan years beginning after 2007. As a result of this bill, we expect to reduce our contributions to the Pension Plan over the next 10 years by a present value amount of $53 million. IMPLEMENTATION OF NEW ACCOUNTING STANDARDS SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our consolidated results of operations when it became effective. We applied the additional guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R). STAFF ACCOUNTING BULLETING NO. 108, CONSIDERING THE EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL STATEMENTS: SAB No. 108 was adopted on December 31, 2006. The CE-27 Consumers Energy Company standard clarifies how we should assess the materiality of prior period financial statement errors in the current period. Prior to the adoption of this standard, we used the "iron-curtain" method to quantify the effects of prior period financial statement errors. The iron-curtain method focuses on the effects of correcting the period-end balance sheet with less emphasis on the effects the correction would have on our consolidated income statement. This standard requires quantification of financial statement errors based on their effect on each of our consolidated financial statements. The adoption of this standard did not have an effect on our financial position or results of operations. 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): In September 2006, the FASB issued SFAS No. 158. This standard requires us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Upon implementation of this standard, we recorded an additional postretirement benefit liability of $643 million, a regulatory asset of $680 million and a reduction of $6 million to AOCI, after tax. This standard also requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of this provision of the standard will have a material effect on our consolidated financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008. NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006, the FASB issued FIN 48, effective for us January 2007. This interpretation provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management's best judgment, it is greater than 50 percent likely that the taxing authority will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return. Our policy is to include interest and penalties accrued, if any, on uncertain tax positions as part of the related tax liability on our consolidated balance sheet and as part of the income tax expense in our consolidated income statement. The impact from adopting FIN 48 should be recorded as a cumulative adjustment to the beginning retained earnings balance and a corresponding adjustment to a current or non-current tax liability. Although we have not yet determined the full effect of FIN 48, we do not expect to record a material adjustment to the January 1, 2007 retained earnings balance. SFAS No. 157, FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a revised definition of "fair value" and gives guidance on how to measure the fair value of assets and liabilities. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value in any new circumstances. However, additional disclosures will be required on the impact and reliability of fair value measurements reflected in our consolidated financial statements. The standard will also eliminate the existing prohibition of recognizing "day one" gains or losses on derivative instruments, and will generally require such gains and losses to be recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS No. 157. We currently do not hold any derivatives that would involve day one gains or losses. SFAS NO. 159, THE FAIR VALUE OPTION FOR FINANCIAL ASSETS AND FINANCIAL LIABILITIES, INCLUDING AN AMENDMENT TO FASB STATEMENT NO. 115: In February 2007, the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard will give us the option to select certain financial instruments and other items, which otherwise are not required to be measured at fair value, and measure those items at fair value. If we choose to elect the fair value option for an item, we would recognize unrealized gains and losses associated with changes in the fair value of the item over time. The statement will also require disclosures for items for which the fair value option has been elected. We are presently evaluating whether we will choose toe elect the fair value option for any financial instruments of other items. CE-28 Consumers Energy Company CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF INCOME (LOSS)
YEARS ENDED DECEMBER 31 ---------------------- 2006 2005 2004 ---- ---- ---- IN MILLIONS OPERATING REVENUE.......................................... $5,721 $5,232 $4,711 EARNINGS FROM EQUITY METHOD INVESTEES...................... 1 1 1 OPERATING EXPENSES Fuel for electric generation............................. 672 605 701 Fuel costs mark-to-market at the MCV Partnership......... 204 (200) 19 Purchased and interchange power.......................... 647 347 224 Purchased power -- related parties....................... 74 68 67 Cost of gas sold......................................... 1,770 1,844 1,468 Cost of gas sold -- related parties...................... -- -- 1 Other operating expenses................................. 895 841 717 Maintenance.............................................. 284 218 227 Depreciation, depletion, and amortization................ 527 484 391 General taxes............................................ 150 214 223 Asset impairment charges................................. 218 1,184 -- ------ ------ ------ 5,441 5,605 4,038 ------ ------ ------ OPERATING INCOME (LOSS).................................... 281 (372) 674 OTHER INCOME (DEDUCTIONS) Accretion expense........................................ (1) (2) (3) Interest and dividends................................... 62 45 11 Gain on asset sales, net................................. 79 -- 1 Regulatory return on capital expenditures................ 26 4 113 Other income............................................. 20 20 16 Other expense............................................ (11) (13) (7) ------ ------ ------ 175 54 131 ------ ------ ------ INTEREST CHARGES Interest on long-term debt............................... 281 289 284 Interest on long-term debt -- related parties............ 1 15 44 Other interest........................................... 17 6 13 Capitalized interest..................................... (10) (38) 25 ------ ------ ------ 289 272 366 ------ ------ ------ INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS (OBLIGATIONS), NET....................................... 167 (590) 439 MINORITY INTERESTS (OBLIGATIONS), NET...................... (110) (447) 7 ------ ------ ------ INCOME (LOSS) BEFORE INCOME TAXES.......................... 277 (143) 432 INCOME TAX (BENEFIT) EXPENSE............................... 91 (47) 152 ------ ------ ------ INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE..................................... 186 (96) 280 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR RETIREMENT BENEFITS, NET OF $- TAX BENEFIT IN 2004.................. -- -- (1) ------ ------ ------ NET INCOME (LOSS).......................................... 186 (96) 279 PREFERRED STOCK DIVIDENDS.................................. 2 2 2 ------ ------ ------ NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER.......... $ 184 $ (98) $ 277 ====== ====== ======
The accompanying notes are an integral part of these statements. CE-29 Consumers Energy Company CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31 ----------------------- 2006 2005 2004 ---- ---- ---- IN MILLIONS CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss)....................................... $ 186 $ (96) $ 279 Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation, depletion, and amortization (includes nuclear decommissioning of $6 per year)......... 527 484 391 Deferred income taxes and investment tax credit.... (113) (225) 137 Regulatory return on capital expenditures.......... (26) (4) (113) Minority interests (obligations), net.............. (110) (447) 7 Fuel costs mark-to-market at the MCV Partnership... 204 (200) 19 Asset impairment charges........................... 218 1,184 -- Capital lease and other amortization............... 37 34 29 Bad debt expense................................... 30 24 20 Gain on sale of assets............................. (79) -- (1) Cumulative effect of changes in accounting......... -- -- 1 Earnings from equity method investees.............. (1) (1) (1) Changes in assets and liabilities: Increase in accounts receivable, notes receivable and accrued revenue................ (67) (294) (112) Increase in inventories......................... (114) (235) (126) Increase (decrease) in accounts payable......... (32) 154 67 Increase (decrease) in accrued expenses......... 35 (13) 31 Increase (decrease) in accrued taxes............ (101) 146 32 Increase (decrease) in the MCV Partnership gas supplier funds on deposit..................... (147) 173 15 Increase in other current and non-current assets........................................ (63) (19) (62) Increase (decrease) in other current and non- current liabilities........................... 90 (25) (18) ----- ------- ------- Net cash provided by operating activities.......... 474 640 595 ----- ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excludes assets placed under capital lease)....................................... (646) (572) (508) Cost to retire property................................. (78) (27) (28) Restricted cash and restricted short-term investments... 126 (162) (3) Investments in Electric Restructuring Implementation Plan................................................. -- -- (7) Investments in nuclear decommissioning trust funds...... (21) (6) (6) Proceeds from nuclear decommissioning trust funds....... 22 39 36 Proceeds from short-term investments.................... -- 145 1,048 Purchase of short-term investments...................... -- (141) (1,052) Maturity of the MCV Partnership restricted investment securities held-to-maturity.......................... 130 318 675 Purchase of the MCV Partnership restricted investment securities held-to-maturity.......................... (131) (270) (674) Cash proceeds from sale of assets....................... 69 2 2 Cash relinquished from sale of assets................... (148) -- -- Other investing......................................... 4 12 -- ----- ------- ------- Net cash used in investing activities.............. (673) (662) (517) ----- ------- -------
CE-30 Consumers Energy Company
YEARS ENDED DECEMBER 31 ----------------------- 2006 2005 2004 ---- ---- ---- IN MILLIONS CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of long term debt................ -- 910 1,055 Retirement of long-term debt............................ (217) (1,028) (963) Payment of common stock dividends....................... (147) (277) (190) Payment of capital and finance lease obligations........ (26) (29) (44) Stockholder's contribution, net......................... 200 700 250 Payment of preferred stock dividends.................... (2) (2) (2) Increase (decrease) in notes payable.................... 15 27 (200) Debt issuance and financing costs....................... (3) (34) (33) ----- ------- ------- Net cash provided by (used in) financing activities...................................... (180) 267 (127) ----- ------- ------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...... (379) 245 (49) CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB INTERPRETATION NO. 46 CONSOLIDATION..................... -- -- 174 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD............ 416 171 46 ----- ------- ------- CASH AND CASH EQUIVALENTS, END OF PERIOD.................. $ 37 $ 416 $ 171 ----- ------- ------- OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE: CASH TRANSACTIONS Interest paid (net of amounts capitalized)................ $ 279 $ 250 $ 324 Income taxes paid (net of refunds, $39, $8, and $50, respectively)........................................ 306 35 (27) Pension and OPEB cash contributions..................... 68 62 62 NON-CASH TRANSACTIONS Other assets placed under capital lease................. $ 7 $ 12 $ 3 ===== ======= =======
The accompanying notes are an integral part of these statements. CE-31 Consumers Energy Company CONSUMERS ENERGY COMPANY CONSOLIDATED BALANCE SHEETS
DECEMBER 31 ----------------- 2006 2005 ---- ---- IN MILLIONS ASSETS PLANT AND PROPERTY (AT COST) Electric.................................................... $ 8,504 $ 8,204 Gas......................................................... 3,273 3,151 Other....................................................... 15 227 ------- ------- 11,792 11,582 Less accumulated depreciation, depletion, and amortization.. 4,983 4,804 ------- ------- 6,809 6,778 Construction work-in-progress............................... 639 509 ------- ------- 7,448 7,287 ------- ------- INVESTMENTS Stock of affiliates......................................... 36 33 Other....................................................... 5 7 ------- ------- 41 40 ------- ------- CURRENT ASSETS Cash and cash equivalents at cost, which approximates market................................................... 37 416 Restricted cash and restricted short-term investments at cost, which approximates market.......................... 57 183 Accounts receivable, notes receivable and accrued revenue, less allowances of $14 in 2006 and $13 in 2005........... 591 674 Accounts receivable -- related parties...................... 5 9 Inventories at average cost Gas in underground storage............................... 1,129 1,068 Materials and supplies................................... 81 75 Generating plant fuel stock.............................. 105 80 Deferred property taxes..................................... 150 159 Regulatory assets -- postretirement benefits................ 19 19 Derivative instruments...................................... -- 242 Prepayments and other....................................... 50 70 ------- ------- 2,224 2,995 ------- ------- NON-CURRENT ASSETS Regulatory assets Securitized costs........................................ 514 560 Additional minimum pension............................... -- 399 Postretirement benefits.................................. 1,131 116 Customer Choice Act...................................... 190 222 Other.................................................... 462 484 Nuclear decommissioning trust funds......................... 602 555 Other....................................................... 233 520 ------- ------- 3,132 2,856 ------- ------- TOTAL ASSETS.................................................. $12,845 $13,178 ======= =======
The accompanying notes are an integral part of these statements. CE-32 Consumers Energy Company
DECEMBER 31 ----------------- 2006 2005 ---- ---- IN MILLIONS STOCKHOLDER'S INVESTMENT AND LIABILITIES CAPITALIZATION Common stockholder's equity Common stock, authorized 125.0 shares; outstanding 84.1 shares for all periods................................... $ 841 $ 841 Paid-in capital............................................. 1,832 1,632 Accumulated other comprehensive income...................... 15 72 Retained earnings since December 31, 1992................... 270 233 ------- ------- 2,958 2,778 Preferred stock............................................. 44 44 Long-term debt.............................................. 4,127 4,303 Non-current portion of capital leases and finance lease obligations.............................................. 42 308 ------- ------- 7,171 7,433 ------- ------- MINORITY INTERESTS............................................ -- 259 ------- ------- CURRENT LIABILITIES Current portion of long-term debt, capital leases and finance leases........................................... 44 112 Current portion of long-term debt -- related parties........ -- 129 Notes payable -- related parties............................ 42 27 Accounts payable............................................ 421 458 Accounts payable -- related parties......................... 18 40 Accrued interest............................................ 66 82 Accrued taxes............................................... 295 400 Deferred income taxes....................................... 11 55 MCV Partnership gas supplier funds on deposit............... -- 193 Other....................................................... 217 171 ------- ------- 1,114 1,667 ------- ------- NON-CURRENT LIABILITIES Deferred income taxes....................................... 847 1,027 Regulatory liabilities Regulatory liabilities for cost of removal............... 1,166 1,120 Income taxes, net........................................ 539 455 Other regulatory liabilities............................. 249 178 Postretirement benefits..................................... 993 308 Asset retirement obligations................................ 497 494 Deferred investment tax credit.............................. 62 67 Other....................................................... 207 170 ------- ------- 4,560 3,819 ------- ------- Commitments and Contingencies (Notes 3, 4, 5, 8, and 10) TOTAL STOCKHOLDER'S INVESTMENT AND LIABILITIES................ $12,845 $13,178 ======= =======
CE-33 Consumers Energy Company CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
YEARS ENDED DECEMBER 31 ------------------------ 2006 2005 2004 ---- ---- ---- IN MILLIONS COMMON STOCK At beginning and end of period(a)....................... $ 841 $ 841 $ 841 ------ ------ ------ OTHER PAID-IN CAPITAL At beginning of period.................................. 1,632 932 682 Stockholder's contribution.............................. 200 700 250 ------ ------ ------ At end of period................................... 1,832 1,632 932 ------ ------ ------ ACCUMULATED OTHER COMPREHENSIVE INCOME Retirement benefits liability At beginning of period............................... (2) (1) -- Retirement benefits liability adjustments(b)......... -- (1) (1) Adjustment to initially apply FASB Statement No. 158, net of tax......................................... (6) -- -- ------ ------ ------ At end of period................................... (8) (2) (1) ------ ------ ------ Investments At beginning of period............................... 18 12 9 Unrealized gain on investments(b).................... 5 6 3 ------ ------ ------ At end of period................................... 23 18 12 ------ ------ ------ Derivative instruments At beginning of period............................... 56 20 8 Unrealized gain (loss) on derivative instruments(b).. (21) 53 23 Reclassification adjustments included in net income (loss)(b).......................................... (35) (17) (11) ------ ------ ------ At end of period................................... -- 56 20 ------ ------ ------ Total Accumulated Other Comprehensive Income.............. 15 72 31 ------ ------ ------ RETAINED EARNINGS At beginning of period.................................. 233 608 521 Net income (loss)....................................... 186 (96) 279 Cash dividends declared -- Common Stock................. (147) (277) (190) Cash dividends declared -- Preferred Stock.............. (2) (2) (2) ------ ------ ------ At end of period................................... 270 233 608 ------ ------ ------ TOTAL COMMON STOCKHOLDER'S EQUITY......................... $2,958 $2,778 $2,412 ====== ====== ======
The accompanying notes are an integral part of these statements. CE-34 Consumers Energy Company
YEARS ENDED DECEMBER 31 ------------------ 2006 2005 2004 ---- ---- ---- IN MILLIONS (a) NUMBER OF SHARES OF COMMON STOCK OUTSTANDING WAS 84,108,789 FOR ALL PERIODS PRESENTED (b) DISCLOSURE OF OTHER COMPREHENSIVE INCOME: Retirement benefits liability Retirement benefits liability adjustment, net of tax (tax benefit) of $-- in 2006, $-- in 2005, and $(1) in 2004............................................ $ -- $ (1) $ (1) Investments Unrealized gain on investments, net of tax of $2 in 2006, $3 in 2005, and $2 in 2004................... 5 6 3 Derivative instruments Unrealized gain (loss) on derivative instruments, net of tax (tax benefit) of $(11) in 2006, $28 in 2005, and $12 in 2004.................................... (21) 53 23 Reclassification adjustments included in net income (loss), net of tax benefit of $(19) in 2006, $(10) in 2005, and $(6) in 2004.......................... (35) (17) (11) Net income (loss)....................................... 186 (96) 279 ---- ---- ---- Total Comprehensive Income (Loss)....................... $135 $(55) $293 ==== ==== ====
CE-35 Consumers Energy Company CONSUMERS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES CORPORATE STRUCTURE: Consumers, a subsidiary of CMS Energy, a holding company, is a combination electric and gas utility company serving Michigan's Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers. We manage our business by the nature of services each provides and operate principally in two business segments: electric utility and gas utility. PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include Consumers, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with FASB Interpretation No. 46(R). We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. We eliminate intercompany transactions and balances. USE OF ESTIMATES: We prepare our consolidated financial statements in conformity with U.S. GAAP. We are required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates. We record estimated liabilities in our consolidated financial statements when it is probable that a loss will be incurred in the future as a result of a current event, and when the amount can be reasonably estimated. For additional details, see Note 3, Contingencies. REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the storage of natural gas when services are provided. We record sales tax on a net basis and exclude it from revenues. ACCOUNTING FOR MISO TRANSACTIONS: We account for MISO transactions on a net basis for all of our generating units combined. We record billing adjustments when we receive invoices and record an expense accrual for future adjustments based on historical experience. CAPITALIZED INTEREST: We capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest for the period is limited to the actual interest cost incurred. Our regulated businesses capitalize AFUDC on regulated construction projects and include such amounts in plant in service. CASH EQUIVALENTS AND RESTRICTED CASH: Cash equivalents are all liquid investments with an original maturity of three months or less. At December 31, 2006, our restricted cash on hand was $57 million. We classify restricted cash dedicated for repayment of Securitization bonds as a current asset, as the related payments occur within one year. COLLECTIVE BARGAINING AGREEMENTS: At December 31, 2006, the Utility Workers of America Union represented approximately 45 percent of our employees. The Union represents Consumers' operating, maintenance, and construction employees and our call center employees. DETERMINATION OF PENSION MRV OF PLAN ASSETS: We determine the MRV for pension plan assets, as defined in SFAS No. 87, as the fair value of plan assets on the measurement date, adjusted by the gains or losses that will not be admitted into MRV until future years. We reflect each year's assets gain or loss in MRV in equal amounts over a five-year period beginning on the date the original amount was determined. We use the MRV in the calculation of net pension cost. EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL STATEMENTS: SAB No. 108 was adopted on December 31, 2006. The standard clarifies how we should assess the materiality of prior period financial statement errors in the current period. Prior to the adoption, of this standard we used the "iron-curtain" method to quantify the effects of prior period financial statement errors. The iron-curtain method focuses on the effects of correcting the period-end balance sheet with less emphasis on the effects the correction would have on our consolidated income statement. This standard requires quantification of financial CE-36 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) statement errors based on their effect on each of our consolidated financial statements. The adoption of this standard did not have an effect on our financial position or results of operations. FINANCIAL AND DERIVATIVE INSTRUMENTS: We record debt and equity securities classified as available-for-sale at fair value determined from quoted market prices. We record debt and equity securities classified as held-to-maturity at cost. On a specific identification basis, we report unrealized gains or losses from changes in fair value of certain available-for-sale debt and equity securities, net of tax, in equity as part of AOCI. We exclude unrealized gains or losses from earnings unless the related changes in fair value are determined to be other than temporary. We reflect unrealized gains or losses on our nuclear decommissioning investments as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our consolidated earnings or cash flows. We account for derivative instruments using SFAS No. 133. We report derivatives on our Consolidated Balance Sheets at their fair value. We record changes in fair value in AOCI if the derivative qualifies for cash flow hedge accounting; otherwise, we record the changes in earnings. For additional details regarding financial and derivative instruments, see Note 5, Financial and Derivative Instruments. IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate the potential impairment of our investments and other long-lived assets, other than goodwill, based on various analyses, including the projection of undiscounted cash flows, whenever events or changes in circumstances indicate that the carrying amount of the investment or asset may not be recoverable. If the carrying amount of the investment or asset exceeds its estimated undiscounted future cash flows, we recognize an impairment loss and write down the investment or asset to its estimated fair value. For additional details, see Note 2, Asset Sales and Impairment Charges. INVENTORY: We use the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities. We use the weighted average cost method for valuing materials and supplies inventory. We use the weighted average cost method for valuing coal inventory and classify these costs as generating plant fuel stock on our Consolidated Balance Sheets. MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property replacement to maintenance expense. We use the direct expense method to account for planned major maintenance activities. We charge planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements. We depreciate utility property using straight-line rates approved by the MPSC. The composite depreciation rates for our properties are:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- Electric utility property.................................. 3.1% 3.1% 3.1% Gas utility property....................................... 3.6% 3.6% 3.7% Other property............................................. 8.2% 7.6% 8.4%
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on the quantity of heat produced for electric generation. For nuclear fuel used after April 6, 1983, we charge certain disposal costs to nuclear fuel expense, recover these costs through electric rates, and remit them to the DOE quarterly. We elected to defer payment for disposal of spent nuclear fuel burned before April 7, 1983. Our DOE liability is $152 million at December 31, 2006 and $145 million at December 31, 2005. This amount includes interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. We have recovered, through electric rates, the amount of this liability, excluding a portion of interest. In conjunction with the sale of Palisades and the Big Rock ISFSI, we will retain this obligation and provide security to Entergy for this obligation in the form of cash, a letter of credit, or other acceptable means. For additional details on disposal of spent nuclear fuel, see Note 3, Contingencies, "Other Electric Contingencies -- Nuclear Matters." CE-37 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) OTHER INCOME AND OTHER EXPENSE: The following tables show the components of Other income and Other expense:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Other income Electric restructuring return.............................. $ 4 $ 6 $ 6 Return on stranded and security costs...................... 5 6 9 Nitrogen oxide allowance sales............................. 8 2 -- Gain on stock.............................................. 1 1 -- All other.................................................. 2 5 1 ---- ---- ---- Total other income........................................... $ 20 $ 20 $ 16 ==== ==== ====
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- IN MILLIONS Other expense Loss on reacquired debt................................... $ -- $ (6) $-- Civic and political expenditures.......................... (2) (2) (2) Donations................................................. (9) -- (1) Loss on SERP investment................................... -- (1) (1) All other................................................. -- (4) (3) ----- ----- ---- Total other expense......................................... $ (11) $ (13) $ (7) ===== ===== ====
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at original cost when placed into service. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, we charge the original cost to accumulated depreciation, along with associated cost of removal, net of salvage. Cost of removal collected from our customers, but not spent, is recorded as a regulatory liability. We capitalize AFUDC on regulated major construction projects. We recognize gains or losses on the retirement or disposal of non-regulated assets in income. For additional details, see Note 7, Asset Retirement Obligations and Note 11, Property, Plant, and Equipment. RECLASSIFICATIONS: We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not affect consolidated net income (loss) for the years presented. RELATED PARTY TRANSACTIONS: We received income from related parties as follows:
TYPE OF INCOME RELATED PARTY 2006 2005 2004 -------------- ------------- ---- ---- ---- IN MILLIONS Income from our investments in related party trusts Consumers' affiliated Trust $-- $1 $1 Preferred Securities companies.....
CE-38 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) We recorded expense from related parties as follows:
TYPE OF COST RELATED PARTY 2006 2005 2004 ------------ ------------- ---- ---- ---- IN MILLIONS Electric generating capacity and energy Affiliates of Enterprises.......... $74 $68 $67 Interest expense on long-term debt Consumers' affiliated Trust 1 15 44 Preferred Securities companies..... Gas purchases CMS ERM............................ -- -- 1 Overhead expense(a) CMS Energy parent company.......... 1 1 -- Gas transportation CMS Bay Area Pipeline, L.L.C....... 4 4 4
-------------- (a) We base our related party transactions on regulated prices, market prices, or competitive bidding. We pay overhead costs to CMS Energy based on an industry allocation methodology, such as the Massachusetts Formula. We own 2.2 million shares of CMS Energy Common Stock with a fair value of $36 million at December 31, 2006. For additional details on our investment in CMS Energy Common Stock, see Note 5, Financial and Derivative Instruments. TRADE RECEIVABLES: Accounts receivable is primarily composed of trade receivables and unbilled receivables. We record our accounts receivable at fair value. We establish an allowance for uncollectible accounts based on historical losses and management's assessment of existing economic conditions, customer trends, and other factors. We assess late payment fees on trade receivables based on contractual past-due terms established with customers. We charge accounts deemed uncollectible to operating expense. UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums, discounts, and expenses incurred in connection with the issuance of long-term debt and amortize those costs over the terms of the debt issues. We expense any refinancing costs as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and expenses and amortize them over the terms of the newly issued debt. UTILITY REGULATION: We account for the effects of regulation using SFAS No. 71. As a result, the actions of regulators affect when we recognize revenues, expenses, assets, and liabilities. We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets. We expect to recover these costs through rates over periods of up to 14 years. CE-39 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) We recognized an OPEB transition obligation in accordance with SFAS No. 106 and established a regulatory asset for the amount that we expect to recover in rates over the next six years.
DECEMBER 31 2006 2005 ----------- ---- ---- IN MILLIONS Securitized costs (Note 4)...................................... $ 514 $ 560 Additional minimum pension liability (Note 6)(a)................ -- 399 Postretirement benefits (Note 6)(a)............................. 1,150 135 Customer Choice Act............................................. 190 222 Electric restructuring implementation plan...................... 40 74 Manufactured gas plant sites (Note 3)........................... 56 62 Abandoned Midland project....................................... 9 9 Unamortized debt costs.......................................... 86 93 Asset retirement obligations (Note 7)........................... 177 169 Stranded costs (Note 3)......................................... 65 63 Other........................................................... 29 14 ------ ------ Total regulatory assets(b)...................................... $2,316 $1,800 ====== ====== Cost of removal (Note 7)........................................ $1,166 $1,120 Income taxes, net (Note 8)...................................... 539 455 Asset retirement obligations (Note 7)........................... 180 165 Other........................................................... 69 13 ------ ------ Total regulatory liabilities(b)................................. $1,954 $1,753 ====== ======
-------------- (a) The change from 2005 to 2006 is largely due to the implementation of 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). For additional details, see Note 6, Retirement Benefits. (b) At December 31, 2006, we classified $19 million of regulatory assets as current regulatory assets and we classified $2.297 billion of regulatory assets as non-current regulatory assets. At December 31, 2005, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.781 billion of regulatory assets as non-current regulatory assets. At December 31, 2006 and December 31, 2005, all of our regulatory liabilities represented non-current regulatory liabilities. NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE: SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a revised definition of "fair value" and gives guidance on how to measure the fair value of assets and liabilities. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value in any new circumstances. However, additional disclosures will be required on the impact and reliability of fair value measurements reflected in our consolidated financial statements. The standard will also eliminate the existing prohibition of recognizing "day one" gains or losses on derivative instruments, and will generally require such gains and losses to be recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS No. 157. We currently do not hold any derivatives that would involve day one gains or losses. SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard will give us the option to select certain financial instruments and other items, which otherwise are not required to be measured at fair value, and measure those items at fair value. If we choose to elect the fair value CE-40 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) option for an item, we would recognize unrealized gains and losses associated with changes in the fair value of the item over time. The statement will also require disclosures for items for which the fair value option has been elected. We are presently evaluating whether we will choose to elect the fair value option for any financial instruments or other items. FIN 48, Accounting for Uncertainties in Income Taxes: We discuss the requirements of this new accounting standard in Note 8, Income Taxes. 2: ASSET SALES AND IMPAIRMENT CHARGES ASSET SALES Gross cash proceeds received from the sale of assets totaled $69 million in 2006. For the year ended December 31, 2006, we sold the following assets:
PRETAX AFTER-TAX DATE SOLD BUSINESS/PROJECT GAIN GAIN --------- ---------------- ------ --------- IN MILLIONS October Land in Ludington, Michigan(a).......................... $ 2 $ 2 November MCV GP II(b)............................................ 77 38 --- --- Total gain on asset sales............................... $79 $40 === ===
-------------- (a) Sale of Ludington Land: We sold 36 parcels of land near Ludington, Michigan. We held a majority share of the land, which we co-owned with DTE Energy. Our portion of the proceeds was approximately $6 million. (b) Sale of our Interest in the MCV Partnership and the MCV Facility: We sold 100 percent of our ownership interest of MCV GP II (the successor to CMS Midland, Inc.) and 100 percent of our ownership of the stock of CMS Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments for $60.5 million. These Consumers subsidiaries held our 49 percent interest in the MCV Partnership and our 35 percent lessor interest in the MCV Facility, held by the FMLP. The transaction is composed of non-real estate and real estate components. Since the carrying value of the MCV Facility, the real estate component of the transaction, exceeded the fair value, we recorded an impairment charge of $218 million. After considering tax effects and minority interest, the impairment charge reduced our consolidated net income by $80 million. Because of the MCV PPA, the transaction is a sale and leaseback for accounting purposes. SFAS No. 98 specifies the accounting required for a seller's sale and simultaneous leaseback involving real estate. We will have continuing involvement with the MCV Partnership through an existing guarantee associated with the future operations of the MCV Facility. As a result, we accounted for the MCV Facility, which is the asset subject to the leaseback, as a financing for accounting purposes and not a sale. We accounted for the non- real estate assets and liabilities associated with the transaction as a sale. As a financing, the MCV Facility remains on our Consolidated Balance Sheets and the related proceeds are recorded as a financing obligation. The value of the finance obligation is based on an allocation of the sale proceeds to the fair values of the net assets sold and fair value of the MCV Facility asset under the financing. The total proceeds of $57 million (net of $3 million of selling expenses) were less than the fair value of the net assets sold. As a result, there were no proceeds remaining to allocate to the MCV Facility and a finance obligation was not recorded. The previously described transaction resulted in an after-tax loss of $41 million. This loss includes the reversal of $30 million, into earnings, of certain cumulative amounts of the MCV Partnership derivative fair value changes that we accounted for in AOCI, the impairment charge on the MCV Facility, and gain on the sale of our interests in the MCV Partnership and the FMLP. For further information, see Note 5, Financial and Derivative Instruments, "Derivative Contracts Associated with the MCV Partnership." CE-41 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table summarizes the impacts of the transaction on net income and stockholder's equity:
DESCRIPTION AFTER-TAX IMPACT ----------- ---------------- IN MILLIONS Asset impairment charges, net of minority interest of $95 million and $43 million in taxes........................................ $(80) General taxes, net of $1 million in taxes......................... 1 Gain on asset sales, net Reclassification of AOCI into earnings, net of $17 million in taxes........................................................ 30 Removal of interests in the MCV Partnership and the FMLP, net of $22 million in taxes......................................... 8 ---- Decrease to consolidated net income............................... $(41) Reclassification of AOCI into earnings, net of $17 million in taxes........................................................ (30) ---- Decrease to stockholder's equity.................................. $(71) ====
ASSET IMPAIRMENT CHARGES As discussed in "Asset Sales," in November 2006, we recorded an impairment charge of $218 million in our Consolidated Statements of Income (Loss). This impairment charge recognizes the reduction in fair value of the MCV Facility's real estate assets and results in an $80 million reduction to our consolidated net income after considering tax effects and minority interest. In the third quarter of 2005, NYMEX forward natural gas price forecasts for the years 2005 through 2010 increased substantially. Additionally, other independent natural gas long-term forward price forecasting organizations indicated their intention to raise their forecasts for the price of natural gas beyond 2010. As a result, the MCV Partnership determined an impairment analysis considering revised forward natural gas price assumptions was required. The MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows. The carrying value of the MCV Partnership's fixed assets exceeded the estimated fair value resulting in impairment charges of $1.159 billion to recognize the reduction in fair value of the MCV Facility's fixed assets and $25 million of interest capitalized during the construction of the MCV Facility. Our 2005 consolidated net income was reduced by $385 million, after considering tax effects and minority interest. Our interests in the MCV Partnership were reported as a component of our "other" business segment. 3: CONTINGENCIES SEC AND DOJ INVESTIGATIONS: During the period of May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These so called round-trip trades had no impact on previously reported consolidated net income, earnings per share or cash flows, but had the effect of increasing operating revenues and operating expenses by equal amounts. CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies. Those two individuals filed a motion to dismiss the SEC action, which was denied. SECURITIES CLASS ACTION LAWSUITS: Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the United States District Court for the Eastern District of Michigan. The cases were consolidated into a single lawsuit (the "Shareholder CE-42 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Action"), which generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the court conditionally certified a class consisting of "all persons who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17, 2002 and who were damaged thereby." The court excluded purchasers of CMS Energy's 8.75 percent Adjustable Convertible Trust Securities ("ACTS") from the class and, in response, a new class action lawsuit was filed on behalf of ACTS purchasers (the "ACTS Action") against the same defendants named in the Shareholder Action. The settlement described in the following paragraph, if approved, will resolve both the Shareholder and ACTS Actions. On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the "MOU") dated December 28, 2006, subject to court approval, regarding settlement of the two class action lawsuits. The settlement was approved by a special committee of independent directors and by the full board of directors. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. The MOU is expected to lead to a detailed stipulation of settlement that will be presented to the assigned federal judge and the affected class in the first quarter of 2007. Under the terms of the MOU, the litigation will be settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy will make a payment of approximately $123 million plus an amount equivalent to interest on the outstanding unpaid settlement balance beginning on the date of preliminary approval of the court and running until the balance of the settlement funds is paid into a settlement account. Out of the total settlement, CMS Energy's insurers will pay approximately $77 million directly to the settlement account. CMS Energy took an approximately $123 million net pre- tax charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS Energy makes no admission of liability under the Shareholder Action and the ACTS Action. ELECTRIC CONTINGENCIES ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates. Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seeking permits to modify the plant from the EPA. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of "routine maintenance." If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric generating plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question. Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental Protection Act, we expect that we will ultimately incur investigation and remedial action costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies. We are a potentially responsible party at several contaminated sites administered under Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties with substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for the known Superfund sites will be between $1 million and $10 million. At December 31, 2006, we have recorded a liability for the minimum amount of our estimated probable Superfund liability. The timing of payments related to the remediation of our Superfund sites is uncertain. Any significant change in assumptions, such as different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs and the timing of our remediation payments. CE-43 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at Ludington. We removed and replaced part of the PCB material. Since proposing a plan to deal with the remaining materials, we have had several conversations with the EPA. The EPA has proposed a rule, which would authorize continued use of such material in place, subject to certain restrictions. We are not able to predict when a final rule will be issued. LITIGATION: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. The judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The plaintiffs also filed suit in the United States Court for the Western District of Michigan, which the judge subsequently dismissed. The plaintiffs have appealed the dismissal to the United States Court of Appeals. We cannot predict the outcome of these appeals. ELECTRIC RATE MATTERS ELECTRIC ROA: In prior orders, the MPSC approved recovery of Stranded Costs incurred from 2002 through 2003 plus the cost of money through the period of collection. At December 31, 2006, we had a regulatory asset for Stranded Costs of $65 million on our Consolidated Balance Sheets. We collect Stranded Costs through a surcharge on ROA customers. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers, which represent a decrease of 46 percent of ROA load compared to the end of December 2005. If downward ROA trends continue, it may extend the time it takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends and their effect on the timely recovery of Stranded Costs. POWER SUPPLY COSTS: To reduce the risk of high power supply costs during peak demand periods and to achieve our reserve margin target, we purchase electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2007 through 2010. As a result, we have an asset of $62 million for unexpired seasonal capacity and energy contracts at December 31, 2006. Capacity cost for these primarily seasonal electric capacity and energy contracts was $17 million in 2006. PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudency in annual plan and reconciliation proceedings. 2005 PSCR Reconciliation: In March 2006, we submitted our 2005 PSCR reconciliation filing to the MPSC. Our filing indicated that 2005 underrecoveries were $36 million for commercial and industrial customers. 2006 PSCR Plan: In August 2006, the MPSC issued an order approving our amended 2006 PSCR plan, which resulted in an increased PSCR factor for the remainder of 2006. PSCR underrecoveries for 2006 were $119 million. These underrecoveries are due to the MPSC delaying recovery of our increased METC costs and coal supply costs, increased bundled sales, and other cost increases beyond those included in the 2006 PSCR plan filings. PSCR 2007 Plan: In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as filed in our September 2006 case filing. The order also approved the incorporation of our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR monthly factor and allowed us to continue to roll in prior year under and overrecoveries into future PSCR plans. We expect to recover fully all of our PSCR costs. When we are unable to collect these costs as they are incurred, there is a negative impact on our cash flows from electric utility operations. We cannot predict the outcome of these proceedings. CE-44 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) OTHER ELECTRIC CONTINGENCIES THE MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35- year power purchase agreement beginning in 1990. We estimate that capacity and energy payments under the MCV PPA will be $620 million per year. The MCV PPA and the associated customer rates are unaffected by the November 2006 sale of our interest in the MCV Partnership. Underrecoveries related to the MCV PPA: The cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. We expensed underrecoveries of $57 million in 2006 and we estimate cash underrecoveries of $39 million in 2007. However, we use the direct savings from the RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy underrecoveries expense. RCP: In January 2005, we implemented the MPSC-approved RCP with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility based on natural gas market prices. This results in fuel cost savings for the MCV Facility, which the MCV Partnership shares with us. The RCP also requires us to contribute $5 million annually to a renewable resources program. As of December 2006, we have contributed $10 million to the renewable resources program. The underlying RCP agreement between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In January 2007, the Michigan Attorney General filed an appeal with the Michigan Supreme Court regarding the MPSC's order approving the RCP. We cannot predict the outcome of this matter. Regulatory Out Provision in the MCV PPA: After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The MCV Partnership has notified us that it takes issue with our intended exercise of the regulatory out provision. We believe that the provision is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out provision, the MCV Partnership has the right to terminate the MCV PPA, which could affect our reserve margin. We anticipate that the MPSC will review our exercise of the regulatory out provision and the likely consequences of such action in 2007. It is possible that in the event that the MCV Partnership ceases performance under the MCV PPA, prior orders could limit recovery of replacement power costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the cost of replacement power, this could result in our costs exceeding the recovery amount allowed by the MPSC. We cannot predict the outcome these matters. THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT: In July 2006, we reached an agreement to sell Palisades to Entergy for $380 million and pay Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. Palisades Asset Sale: The sale is subject to various regulatory approvals, including the MPSC's approval of the power purchase agreement and the NRC's approval of the transfer of the operating license to Entergy and other related matters. In February 2007, the FERC issued an order approving the sale of power to us under the power purchase agreement and granted other related approvals, with what we believe are minor exceptions and conditions that we believe can be adequately accepted. In October 2006, the Federal Trade Commission issued a notice that neither it nor the DOJ's Antitrust Division plans to take enforcement action on the sale. The final purchase price will be subject to various closing adjustments such as working capital and capital expenditure adjustments, adjustments for nuclear fuel usage and inventory, and the date of closing. However, termination of the sale agreement can occur if the closing does not take place by January 2008. To accommodate delays in receiving regulatory approval, extension of the closing can occur for up to six months. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur. Under the agreement, if the transaction does not close by March 1, 2007, a reduction in the purchase price occurs of approximately $80,000 per day, with additional costs if the deal does not close by June 1, 2007. Based on the MPSC's published schedule for the contested case proceedings regarding this transaction, we target to close on CE-45 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) the transaction in the second quarter of 2007. Based on the anticipated closing date, this delay would result in a purchase price reduction for Palisades of approximately $5 million. We estimate that the Palisades sale will result in a $31 million premium above the Palisades asset value at the anticipated closing date after accounting for estimated sales-related costs. We expect that this premium will benefit our customers. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur. We have notified the NMC that we plan to terminate the NMC's operation of Palisades, if the sale is completed, which would require us to pay the NMC an estimated $12 million. Due to the regulatory approvals pending, we have not recorded this contingent obligation. Palisades Power Purchase Agreement: As part of the transaction, Entergy will sell us 100 percent of the plant's output up to its current capacity of 798 MW under a 15-year power purchase agreement. During the term of the power purchase agreement, Entergy is obligated to supply, and we are obligated to take, all capacity and energy from the Palisades plant, exclusive of uprates above the plant's presently specified capacity. When the plant is not operating or is derated, under certain circumstances Entergy can elect to provide replacement power from another source at the rates set in the power purchase agreement. Otherwise, we would have to obtain replacement power from the market. However, we are only obligated to pay Entergy for capacity and energy actually delivered by Entergy either from the plant or from an allowable replacement source chosen by Entergy. If Entergy schedules a plant outage in June, July or August, Entergy is required to provide replacement power at power purchase agreement rates. There are significant penalties incurred by Entergy if the delivered energy fails to achieve a minimum capacity factor level during July and August. Over the term of the power purchase agreement, the pricing terms are such that Consumers' ratepayers will retain the benefits of the Palisades plant's low-cost nuclear generation. Because of the power purchase agreement that will be in place between Consumers and Entergy, the transaction is effectively a sale and leaseback for accounting purposes. SFAS No. 98 specifies the accounting required for a seller's sale and simultaneous leaseback transaction involving real estate, including real estate with equipment. Due to forms of continuing involvement, we will account for the transaction as a financing for accounting purposes and not a sale. As such, we have not classified the assets as held for sale on our Consolidated Balance Sheets. NUCLEAR PLANT DECOMMISSIONING: The MPSC and the FERC regulate the recovery of costs to decommission, or remove from service, our Big Rock and Palisades nuclear plants. Decommissioning funding practices approved by the MPSC require us to file a report on the adequacy of funds for decommissioning at three-year intervals. We prepared and filed updated cost estimates for Big Rock and Palisades in March 2004. Excluding additional costs for spent nuclear fuel storage due to the DOE's failure to accept this spent nuclear fuel on schedule, these reports show a decommissioning cost of $361 million for Big Rock and $868 million for Palisades. Big Rock's estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. Updated cost projections for Big Rock indicate an anticipated decommissioning cost of $390 million as of December 2006. BIG ROCK: In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. In our March 2004 report to the MPSC, we indicated that we would manage the decommissioning trust fund to meet annual NRC financial assurance requirements by withdrawing NRC radiological decommissioning costs from the fund and initially funding non-NRC greenfield costs out of corporate funds. In March 2006, we contributed $16 million to the trust fund from our corporate funds to support NRC radiological decommissioning costs. Excluding the additional nuclear fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we are projecting that the level of funds provided by the trust will fall short of the amount needed to complete the decommissioning by an additional $37 million. This total of $53 million, which are costs associated with NRC radiological and non-NRC greenfield decommissioning work, are being funded out of corporate funds. We plan to seek recovery of such expenditures recorded on our consolidated balance sheets in future filings with the MPSC. CE-46 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) We have incurred Big Rock expenditures, excluding nuclear fuel storage costs, of $41 million for the year ended December 31, 2006, and cumulative expenditures through December 31, 2006 of $386 million. These activities had no material impact on consolidated net income. At December 31, 2006, we have an investment in nuclear decommissioning corporate funded trust funds of $4 million for Big Rock. In addition, at December 31, 2006, we have charged $10 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock. PALISADES: Excluding additional nuclear fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we concluded, based on the cost estimates filed in March 2004, that the existing Palisades' surcharge of $6 million needed to be increased to $25 million annually, beginning January 2006. A settlement agreement was approved by the MPSC, providing for the continuation of the existing $6 million annual decommissioning surcharge through 2011, which was our original license expiration date, and for the next periodic review to be filed in March 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability. At December 31, 2006, we have an investment in the MPSC nuclear decommissioning trust funds of $587 million for Palisades. In addition, at December 31, 2006, we have a FERC decommissioning trust fund with a balance of $11 million. In the FERC's February 2007 order regarding the Pailsades sale, the FERC granted our request to apply the $11 million FERC decommissioning trust fund balance toward the Big Rock decommissioning shortfall, subject to the outcome of the NRC operating license transfer proceedings and completion of the Palisades sale transaction. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 7, Asset Retirement Obligations. In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. In January 2007, the NRC renewed the Palisades operating license for 20 years, extending it to 2031. At this time, we cannot determine what impact this will have on decommissioning costs or the adequacy of funding. Initial estimates of decommissioning costs, assuming a plant retirement date of 2031, show decommissioning costs of either $818 million or $1.049 billion for Palisades, depending on the decommissioning methodology assumed. These costs, which exclude additional costs for spent nuclear fuel storage due to the DOE's failure to accept spent nuclear fuel on schedule, are given in 2003 dollars. NUCLEAR MATTERS: DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other utilities participated, has not been successful in producing more specific relief for the DOE's failure to accept the spent nuclear fuel. There are two court decisions that support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. Over 60 utilities have initiated litigation in the United States Court of Claims. We filed our complaint in December 2002. If our litigation against the DOE is successful, we plan to use any recoveries as reimbursement for the incurred costs of spent nuclear fuel storage. We can make no assurance that the litigation against the DOE will be successful. In 2002, the site at Yucca Mountain, Nevada was designated for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE, in due course, will submit a final license application to the NRC for the repository. The application and review process is estimated to take several years. Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $30 million in any policy year if insured losses in excess of NEIL's CE-47 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) maximum policyholders surplus occur at our, or any other member's, nuclear facility. NEIL's policies include coverage for acts of terrorism. At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear energy hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. Part of the Price-Anderson Act's financial protection is a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed if a nuclear incident occurs at any nuclear generating facility. The maximum assessment against us could be $101 million per occurrence, limited to maximum annual installment payments of $15 million. We also maintain insurance under a program that covers tort claims for bodily injury to nuclear workers caused by nuclear hazards. The policy contains a $300 million nuclear industry aggregate limit. Under a previous insurance program providing coverage for claims brought by nuclear workers, we remain responsible for a maximum assessment of up to $6 million. This requirement will end December 31, 2007. Big Rock remains insured for nuclear liability up to $544 million through nuclear insurance and NRC indemnity, and maintains a nuclear property insurance policy from NEIL. Insurance policy terms, limits, and conditions are subject to change during the year as we renew our policies. GAS CONTINGENCIES GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remediation costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through proceeds derived from a settlement with insurers and MPSC-approved rates. At December 31, 2006, we have a liability of $24 million, net of $59 million of expenditures incurred to date, and a regulatory asset of $56 million. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs and the timing our remediation payments. GAS RATE MATTERS GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudency in annual plan and reconciliation proceedings. CE-48 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table summarizes our GCR reconciliation filings with the MPSC: GAS COST RECOVERY RECONCILIATION
NET OVER- GCR COST GCR YEAR DATE FILED ORDER DATE RECOVERY OF GAS SOLD DESCRIPTION OF NET OVERRECOVERY --------- ---------- ---------- ---------- ------------ ---------------------------------- 2004-2005 June 2005 April 2006 $2 million $1.4 billion The net overrecovery includes interest expense through March 2005 and refunds that we received from our suppliers that are required to be refunded to our customers. 2005-2006 June 2006 Pending $3 million $1.8 billion The net overrecovery includes $1 million interest income through March 2006, which resulted from a net underrecovery position during the majority of the GCR period.
GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan year, which resulted in approval of a settlement agreement and established a fixed price cap of $10.10 per mcf for the December 2005 through March 2006 billing period. We were able to maintain our billing GCR factor below the authorized level for that period. The order was appealed to the Michigan Court of Appeals by one intervenor. We are unable to predict the outcome of this proceeding. GCR plan for year 2006-2007: In December 2005, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2006 through March 2007. Our request proposed using a GCR factor consisting of: - a base GCR ceiling factor of $11.10 per mcf, plus - a quarterly GCR ceiling price adjustment contingent upon future events. In July 2006, all parties signed a partial settlement agreement, which calls for a base GCR ceiling factor of $9.48 per mcf. The settlement agreement base GCR ceiling factor is subject to a quarterly GCR ceiling price adjustment mechanism. The adjustment mechanism allows an adjustment of the base ceiling factor to reflect a portion of cost increases, if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. The MPSC approved the settlement agreement in August 2006. The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor for the month of February 2007 is $7.63 per mcf. GCR plan for year 2007-2008: In December 2006, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2007 through March 2008. Our request proposed using a GCR factor consisting of: - a base GCR ceiling factor of $8.47 per mcf, plus - a quarterly GCR ceiling price adjustment contingent upon future events. 2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC for an annual gas rate increase of $132 million. In May 2006, the MPSC issued an order granting us interim rate relief of $18 million annually. In November 2006, the MPSC issued an order granting rate relief of $81 million, which included the $18 million of interim relief granted in May 2006. The MPSC authorized an 11 percent return on common equity, a reduction from our then current 11.4 percent authorized rate of return. In addition, the order made permanent the collection of a $58 million surcharge granted in October 2004. 2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC for an annual gas rate increase of $88 million and an 11.25 percent authorized return on equity. We have proposed the use of a Revenue Decoupling CE-49 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) and Conservation Incentive Mechanism for residential and general service rate classes to help assure a reasonable opportunity to recover costs that do not fluctuate with volumetric changes. OTHER CONTINGENCIES OTHER: In addition to the matters disclosed within this Note, we are party to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters. We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or future results of operations. FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: The Interpretation requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee. The following table describes our guarantees at December 31, 2006:
EXPIRATION MAXIMUM CARRYING GUARANTEE DESCRIPTION ISSUE DATE DATE OBLIGATION AMOUNT --------------------- ---------- ---------- ---------- -------- IN MILLIONS Surety bonds and other indemnifications Various Various $ 1 -- Guarantee January 1987 March 2016 85 -- Nuclear insurance retrospective premiums Various Indefinite 137 --
The following table provides additional information regarding our guarantees:
EVENTS THAT WOULD GUARANTEE DESCRIPTION HOW GUARANTEE AROSE REQUIRE PERFORMANCE --------------------- ------------------- ------------------- Surety bonds and other indemnifications Normal operating Nonperformance activity, permits and licenses Guarantee Agreement to provide MCV Partnership's power and steam to Dow nonperformance or non- payment under a related contract Nuclear insurance retrospective premiums Normal operations of Call by NEIL and Price- nuclear plants Anderson Act for nuclear incident
At December 31, 2006, none of our guarantees contained provisions allowing us to recover, from third parties, amounts paid under the guarantees with the exception of the Consumers guarantee to provide power and steam to Dow. We sold our interests in the MCV Partnership and the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments to pay Consumers $85 million, subject to certain reimbursement rights, if Dow terminates an agreement under which the MCV Partnership provides it power and steam. This agreement expires in March 2016, subject to certain terms and conditions. The purchaser secured their reimbursement obligation with an irrevocable letter of credit of up to $85 million. We enter into various agreements containing tax and other indemnification provisions in connection with a variety of transactions, including the sale of our interests in the MCV Partnership and the FMLP. While we are unable to estimate the maximum potential obligation related to these indemnities, we consider the likelihood that we CE-50 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) would be required to perform or incur significant losses related to these indemnities and the guarantees listed in the preceding tables to be remote. 4: FINANCINGS AND CAPITALIZATION Long-term debt at December 31 follows:
INTEREST RATE (%) MATURITY 2006 2005 ----------------- -------- ---- ---- (IN MILLIONS) First mortgage bonds...................... 4.250 2008 $ 250 $ 250 4.800 2009 200 200 4.400 2009 150 150 4.000 2010 250 250 5.000 2012 300 300 5.375 2013 375 375 6.000 2014 200 200 5.000 2015 225 225 5.500 2016 350 350 5.150 2017 250 250 5.650 2020 300 300 5.650 2035 147 150 5.800 2035 175 175 ------ ------ 3,172 3,175 ------ ------ Senior notes.............................. 6.375 2008 159 159 6.875 2018 180 180 ------ ------ 339 339 ------ ------ Securitization bonds...................... 5.384(a) 2007-2015 340 369 ------ ------ FMLP Debt: Subordinated secured notes............. 13.250 -- 56 Tax-exempt subordinated secured notes.. 6.875 -- 137 Tax-exempt subordinated secured notes.. 6.750 -- 14 ------ ------ -- 207 ------ ------ Nuclear fuel disposal liability........... (b) 152 145 Tax-exempt pollution control revenue bonds.................................. Various 2010-2035 161 161 ------ ------ 313 306 ------ ------ Total principal amounts outstanding......... 4,164 4,396 Current amounts........................... (31) (85) Net unamortized discount.................. (6) (8) ------ ------ Total Long-term debt........................ $4,127 $4,303 ====== ======
-------------- (a) Represents the weighted average interest rate at December 31, 2006 (5.295 percent at December 31, 2005). (b) Maturity date uncertain. DEBT RETIREMENTS: The following is a summary of significant long-term debt retirements during 2006:
PRINCIPAL (IN MILLIONS) INTEREST RATE (%) RETIREMENT DATE MATURITY DATE ------------- ----------------- --------------- ------------- Long-term debt -- related parties... $129 9.00 February 2006 June 2031 FMLP debt........................... 56 13.25 July 2006 July 2006 FMLP debt(a)........................ 151 Various November 2006 July 2009 ---- Total............................. $336 ====
CE-51 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) -------------- (a) FMLP debt of $151 million was removed as part of the November 2006 transaction in which we sold our interest in the FMLP. FIRST MORTGAGE BONDS: We secure our FMB by a mortgage and lien on substantially all of our property. Our ability to issue FMB is restricted by certain provisions in the first mortgage bond indenture and the need for regulatory approvals under federal law. Restrictive new issuance provisions in our first mortgage bond indenture include achieving a two-times interest coverage ratio and having sufficient net unfunded property additions. SECURITIZATION BONDS: Certain regulatory assets collateralize Securitization bonds. The bondholders have no recourse to our other assets. Through our rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses on the Securitization bonds. Securitization surcharges collected are remitted to a trustee for the Securitization bonds and are not available to our creditors. Securitization surcharges totaled $50 million in 2006 and 2005. DEBT MATURITIES: At December 31, 2006, the aggregate annual contractual maturities for long-term debt for the next five years are:
PAYMENTS DUE ---------------------------- 2007 2008 2009 2010 2011 ---- ---- ---- ---- ---- (IN MILLIONS) Long-term debt....................................... $31 $441 $384 $343 $37 === ==== ==== ==== ===
REGULATORY AUTHORIZATION FOR FINANCINGS: In May 2006, the FERC issued an order authorizing us to issue up to $2.0 billion of secured and unsecured short- term securities for the following purposes: - up to $1.0 billion for general corporate purposes, - up to $1.0 billion of FMB or other securities to be issued solely as collateral for other short-term securities. Also in May 2006, the FERC issued an order authorizing us to issue up to $5.0 billion of secured and unsecured long-term securities for the following purposes: - up to $1.5 billion for general corporate purposes, - up to $1.0 billion for purposes of refinancing or refunding existing long-term debt, and - up to $2.5 billion of FMB or other securities to be issued solely as collateral for other long-term securities. The authorizations are for a two-year period beginning July 1, 2006 and ending June 30, 2008. Any long-term issuances during the two-year authorization period are exempt from FERC's competitive bidding and negotiated placement requirements. REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities with banks are available at December 31, 2006:
OUTSTANDING AMOUNT OF AMOUNT LETTERS-OF- AMOUNT COMPANY EXPIRATION DATE FACILITY BORROWED CREDIT AVAILABLE ------- --------------- --------- -------- ----------- --------- (IN MILLIONS) Consumers........................... March 30, 2007 $300 $-- $-- $300 Consumers........................... May 18, 2010 500 -- 58 442
Effective February 2007, we terminated the $300 million facility. DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at December 31, 2006, we had $215 million of unrestricted retained earnings available to pay common stock dividends. Covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. Provisions of the Federal Power CE-52 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Act and the Natural Gas Act effectively restrict dividends to the amount of our retained earnings. During 2006, we paid $147 million in common stock dividends to CMS Energy. SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we sell certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. The special purpose entity sold $325 million of receivables at December 31, 2006 and December 31, 2005. We continue to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against our other assets for failure of a debtor to pay when due and no right to any receivables not sold. We have neither recorded a gain or loss on the receivables sold nor retained interest in the receivables sold. Certain cash flows under our accounts receivable sales program are shown in the following table:
YEARS ENDED DECEMBER 31 2006 2005 ----------------------- ---- ---- (IN MILLIONS) Net cash flow as a result of accounts receivable financing...... $ -- $ 21 Collections from customers...................................... $5,684 $4,859 ====== ======
PREFERRED STOCK: Our Preferred Stock outstanding follows:
OPTIONAL NUMBER OF SHARES REDEMPTION ---------------- DECEMBER 31 SERIES PRICE 2006 2005 2006 2005 ----------- ------ ---------- ---- ---- ---- ---- (IN MILLIONS) Preferred Stock Cumulative $100 par value, Authorized 7,500,000 shares, with no mandatory redemption.......................... $4.16 $103.25 68,451 68,451 $ 7 $ 7 $4.50 $110.00 373,148 373,148 37 37 --- --- Total Preferred Stock.................... $44 $44 === ===
5: FINANCIAL AND DERIVATIVE INSTRUMENTS FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments or other valuation techniques. The cost and fair value of our long-term financial debt instruments are as follows:
2006 2005 ---------------------------- ---------------------------- FAIR UNREALIZED FAIR UNREALIZED DECEMBER 31 COST VALUE GAIN COST VALUE (LOSS) ----------- ------ ------ ---------- ------ ------ ---------- IN MILLIONS Long-term debt(a).................... $4,158 $4,111 $47 $4,388 $4,393 $(5) Long-term debt -- related parties(b)......................... -- -- -- 129 131 (2)
-------------- (a) Includes current maturities of $31 million at December 31, 2006 and $85 million at December 31, 2005. Settlement of long-term debt is generally not expected until maturity. (b) Includes current maturities of $129 million at December 31, 2005. CE-53 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The summary of our available-for-sale investment securities is as follows:
2006 2005 -------------------------------------- -------------------------------------- UNREALIZED UNREALIZED FAIR UNREALIZED UNREALIZED FAIR DECEMBER 31 COST GAINS LOSSES VALUE COST GAINS LOSSES VALUE ----------- ---- ---------- ---------- ----- ---- ---------- ---------- ----- IN MILLIONS Common stock of CMS Energy(a)................. $ 10 $ 26 $-- $ 36 $ 10 $ 23 $-- $ 33 Nuclear decommissioning investments(b): Equity securities......... 140 150 (4) 286 134 123 (5) 252 Debt securities........... 307 4 (2) 309 287 6 (2) 291 SERP: Equity securities......... 17 9 -- 26 16 6 -- 22 Debt securities........... 6 -- -- 6 8 -- -- 8
-------------- (a) At December 31, 2006, we held 2.2 million shares, and at December 31, 2005, we held 2.3 million shares of CMS Energy Common Stock. (b) Nuclear decommissioning investments include cash and cash equivalents and accrued income totaling $7 million at December 31, 2006 and $12 million at December 31, 2005. Unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities. The fair value of available-for-sale debt securities by contractual maturity at December 31, 2006 is follows:
(IN MILLIONS) Due in one year or less............................................. $ 38 Due after one year through five years............................... 94 Due after five years through ten years.............................. 73 Due after ten years................................................. 110 ---- Total............................................................. $315 ----
In July 2006, we reached an agreement to sell Palisades and the Big Rock ISFSI to Entergy. Entergy will assume responsibility for the future decommissioning of the plant and for storage and disposal of spent nuclear fuel. Accordingly, upon completion of the sale, we will transfer $400 million of nuclear decommissioning trust fund assets to Entergy and retain $205 million. We will also be entitled to receive a return of $147 million, pending either a favorable federal tax ruling regarding the release of the funds, or if no such ruling is issued, after decommissioning of the Palisades site is complete. These estimates fluctuate based on existing market conditions and the closing date of the transaction. The disposition of the retained and receivable nuclear decommissioning funds is subject to regulatory proceedings. Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $91 million at December 31, 2005. They were removed as part of the November 2006 transaction in which we sold our interest in the MCV Partnership. These securities represent funds restricted primarily for future lease payments and are classified as Other assets on our Consolidated Balance Sheets. These investments had original maturity dates of approximately one year or less and, because of their short-term maturities, carrying amounts approximate fair value. DERIVATIVE INSTRUMENTS: In order to limit our exposure to certain market risks, we may enter into various risk management contracts, such as swaps, options, futures, and forward contracts. These contracts, used primarily to manage our exposure to changes in interest rates and commodity prices, are entered into for purposes other than trading. We enter into these contracts using established policies and procedures, under the direction of both: - an executive oversight committee consisting of senior management representatives, and - a risk committee consisting of business unit managers. CE-54 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative, it is recorded on our consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. From time to time, we enter into cash flow hedges. If a derivative qualifies for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported in AOCI; otherwise, the changes are reported in earnings. For a derivative instrument to qualify for cash flow hedge accounting: - the relationship between the derivative instrument and the forecasted transaction being hedged must be formally documented at inception, - the derivative instrument must be highly effective in offsetting the hedged transaction's cash flows, and - the forecasted transaction being hedged must be probable. If a derivative qualifies for cash flow hedge accounting treatment and gains or losses are recorded in AOCI, those gains or losses will be reclassified into earnings in the same period or periods the hedged forecasted transaction affects earnings. If a cash flow hedge is terminated early because it is determined that the forecasted transaction will not occur, any gain or loss recorded in AOCI at that date is recognized immediately in earnings. If a cash flow hedge is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and then reclassified to earnings when the forecasted transaction affects earnings. The ineffective portion, if any, of all hedges is recognized in earnings. To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of our counterparties. The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because: - they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MWh of electricity or bcf of natural gas), - they qualify for the normal purchases and sales exception, or - there is not an active market for the commodity. Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. If an active market for coal develops in the future, some of these contracts may qualify as derivatives and the resulting mark-to-market impact on earnings could be material. In 2005, the MISO began operating the Midwest Energy Market. As of December 31, 2006, we have determined that, due to the increased liquidity for electricity within the Midwest Energy Market since its inception, it is our best judgment that this market should be considered an active market, as defined by SFAS No. 133. This conclusion does not impact how we account for our electric capacity and energy contracts, however, because these contracts qualify for the normal purchases and sales exception and, as a result, are not required to be marked-to-market. CE-55 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Derivative accounting is required for certain contracts used to limit our exposure to commodity price risk. The following table summarizes our derivative instruments:
DECEMBER 31 2006 2005 ----------- ----------------------- ------------------------ FAIR UNREALIZED FAIR UNREALIZED DERIVATIVE INSTRUMENTS COST VALUE GAIN COST VALUE GAIN (LOSS) ---------------------- ---- ----- ---------- ---- ----- ----------- (In Millions) Gas supply option contracts................ $-- $-- $-- $ 1 $ (1) $ (2) FTRs....................................... -- -- -- -- 1 1 Derivative contracts associated with the MCV Partnership: Long-term gas contracts(a)............... -- -- -- -- 205 205 Gas futures, options, and swaps(a)....... -- -- -- -- 223 223 === === === === ==== ====
-------- (a) The fair value of the MCV Partnership's long-term gas contracts and gas futures, options, and swaps has decreased to $0 as a result of the sale of our interest in the MCV Partnership in November 2006. In conjunction with that sale, our interest in these contracts was also sold and, as a result, we no longer record the fair value of these contracts on our Consolidated Balance Sheets. At December 31, 2005, we recorded the fair value of our derivative contracts in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets. GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses gas supply call and put options to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. As part of regulatory accounting, the mark-to-market gains and losses associated with these options are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on our consolidated balance sheet as a regulatory asset or liability. FTRS: With the creation of the Midwest Energy Market, FTRs were established. FTRs are financial instruments that manage price risk related to electricity transmission congestion. An FTR entitles its holder to receive compensation (or, conversely, to remit payment) for congestion-related transmission charges. As part of regulatory accounting, the mark-to-market gains and losses associated with these instruments are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on our consolidated balance sheet as a regulatory asset or liability. DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: In November 2006, we sold our interest in the MCV Partnership. In conjunction with that sale, our interest in all of the MCV Partnership's long-term gas contracts and related futures, options, and swaps was sold. Before the sale, we accounted for certain long-term gas contracts and all of the related futures, options, and swaps as derivatives. Long-term gas contracts: The MCV Partnership used long-term gas contracts to purchase and manage the cost of the natural gas it needed to generate electricity and steam. The MCV Partnership determined that certain of these contracts qualified as normal purchases under SFAS No. 133. Accordingly, we did not recognize these contracts at fair value on our Consolidated Balance Sheets. The MCV Partnership also held certain long-term gas contracts that did not qualify as normal purchases because they contained volume optionality or because the gas was not expected to be used to generate electricity or steam in the normal course of business. Accordingly, prior to the sale, we accounted for these contracts as derivatives, with changes in fair value recorded in earnings each quarter. During 2006, through the date of the sale, we recorded a $151 million loss, before considering tax effects and minority interest, associated with the net decrease in fair value of these long-term gas contracts. This loss is included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income CE-56 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (Loss). As a result of the sale, we no longer consolidate the MCV Partnership. Accordingly, we will no longer record the fair value of the long-term gas contracts on our Consolidated Balance Sheets and will not be required to record gains or losses related to changes in the fair value of these contracts in earnings. Gas Futures, Options, and Swaps: The MCV Partnership entered into natural gas futures, options, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas. The MCV Partnership used these financial instruments to: - ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam, and - manage price risk by fixing the price to be paid for natural gas on some of its long-term gas contracts. Certain of the futures and swaps held by the MCV Partnership qualified for cash flow hedge accounting and, prior to the sale, we recorded our proportionate share of their mark-to-market gains and losses in AOCI. As of the date of the sale, we had accumulated a net gain of $30 million, net of tax and minority interest, in AOCI representing our proportionate share of mark-to-market gains from these cash flow hedges. After the sale, this amount was reclassified to and recognized in earnings as a reduction of the total loss on the sale in our Consolidated Statements of Income (Loss). The remaining futures, options, and swap contracts held by the MCV Partnership did not qualify as cash flow hedges and we recorded any changes in their fair value in earnings each quarter. During 2006, through the date of the sale, we recorded a $53 million loss, before considering tax effects and minority interest, associated with the net decrease in fair value of these contracts. This loss is included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss). As a result of the sale, we will no longer record the fair value of the futures, options, and swaps on our Consolidated Balance Sheets and will not be required to record gains or losses related to changes in the fair value of these contracts in earnings or AOCI. For additional details on the sale of our interest in the MCV Partnership, see Note 2, Asset Sales and Impairment Charges. 6: RETIREMENT BENEFITS We provide retirement benefits to our employees under a number of different plans, including: - a non-contributory, defined benefit Pension Plan, - a cash balance Pension Plan for certain employees hired between July 1, 2003 and August 31, 2005, - a DCCP for employees hired on or after September 1, 2005, - benefits to certain management employees under SERP, - a defined contribution 401(k) Savings Plan, - benefits to a select group of management under the EISP, and - health care and life insurance benefits under OPEB. Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan's assets are not distinguishable by company. On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of 5 percent of base pay to the existing employees' Savings Plan. No employee contribution is required in order to receive the plan's employer contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP expense was $2 million for the year ended December 31, 2006 and less than $1 million for the year ended December 31, 2005. CE-57 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Effective January 11, 2006, the MPSC electric rate order authorized us to include $33 million of electric pension expense in our electric rates. Effective November 21, 2006, the MPSC gas rate order authorized us to include $22 million of gas pension expense in our gas rates. Due to the volatility of these costs, the orders also established a pension equalization mechanism to track actual costs. If actual pension expenses are greater than the amounts included in rate cases, the difference will be recognized as a regulatory asset for future recovery from customers. If actual pension expenses are less than the amounts included in rate cases, the difference will be recognized as a regulatory liability, and refunded to our customers. The difference between pension expenses allowed in Consumers' rate cases and Consumers' $66 million net pension cost under SFAS No. 87 resulted in the recognition of a regulatory asset of $11 million. SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code. SERP trust earnings are taxable and trust assets are included in our consolidated assets. Trust assets were $32 million at December 31, 2006 and $30 million at December 31, 2005. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $37 million at December 31, 2006 and $35 million at December 31, 2005. On April 1, 2006, we implemented a Defined Contribution Supplemental Executive Retirement Plan (DC SERP) and froze further new participation in the defined benefit SERP. The DC SERP provides participants benefits ranging from 5 percent to 15 percent of total compensation. The DC SERP requires a minimum of five years of participation before vesting. Our contributions to the plan, if any, will be placed in a grantor trust. Trust assets were less than $1 million at December 31, 2006. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The DC SERP expense was less than $1 million for the year ended December 31, 2006. 401(k): The employer's match for the 401(k) Savings Plan, which was suspended on September 1, 2002, resumed on January 1, 2005. The employer's match is in CMS Energy Common Stock. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages. The total 401(k) Savings Plan cost was $14 million for the year ended December 31, 2006 and $12 million for the year ended December 31, 2005. Beginning May 1, 2007 the CMS Energy Common Stock Fund will no longer be an investment option available for new investments in the 401(k) Savings Plan and the employer's match will no longer be in CMS Energy Common Stock. Participants will have the opportunity to reallocate investments in CMS Energy Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment options. At February 20, 2007, there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy Stock Fund. The MCV Partnership sponsors a defined contribution retirement plan and a 401(k) Savings Plan covering all employees. Amounts contributed under these plans were $1 million for the period January 1, 2006 through November 21, 2006 and $1 million for each of the years ended December 31, 2005 and 2004. EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premiums for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was less than $1 million for each of the years ended December 31, 2006 and 2005. The ABO for the EISP was less than $1 million at December 31, 2006 and December 31, 2005. OPEB: The OPEB plan covers all regular full-time employees covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least 10 full years of applicable continuous service. Regular full-time employees who qualify for a disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs were based on the assumption that costs would increase 10 percent in 2006. Starting in 2007, we will use two health care trend rates: CE-58 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) one for retirees under 65 and the other for retirees 65 and over. The two health care trend rates recognize that prescription drug costs are increasing at a faster pace than other medical claim costs and that prescription drug costs make up a larger portion of expenses for retirees age 65 and over. The 2007 rate of increase for OPEB health costs for those under 65 is expected to be 9 percent and for those over 65 is expected to be 10.5 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2011 and for those over 65 by 2013 and thereafter. Effective January 11, 2006, the MPSC electric rate order authorized us to include $28 million of electric OPEB expense in our electric rates. Effective November 21, 2006, the MPSC gas rate order authorized us to include $21 million of gas OPEB expense in our gas rates. Due to the volatility of these costs, the orders also established an OPEB equalization mechanism to track actual costs. If actual OPEB expenses are greater than the amounts included in rate cases, the difference will be recognized as a regulatory asset for future recovery from our customers. If actual OPEB expenses are less than the amounts included in rate cases, the difference will be recognized as a regulatory liability, and refunded to our customers. The difference between OPEB expenses allowed in Consumers' rate cases and Consumers' $51 million net OPEB cost under SFAS No. 106 resulted in the recognition of a regulatory asset of $2 million. The MCV Partnership sponsors defined cost postretirement health care plans that cover all full-time employees, except key management. The ABO of the MCV Partnership's postretirement plans was $5 million at December 31, 2005. The MCV Partnership's net periodic postretirement health care cost for the period January 1, 2006 through November 21, 2006 and year ended December 31, 2005 was less than $1 million. The health care cost trend rate assumption affects the estimated costs recorded. A one percentage point change in the assumed health care cost trend assumption would have the following effects:
ONE ONE PERCENTAGE PERCENTAGE POINT INCREASE POINT DECREASE -------------- -------------- (IN MILLIONS) Effect on total service and interest cost component..................................... $ 18 $ (15) Effect on postretirement benefit obligation..... $211 $(179)
Upon adoption of SFAS No. 106, at the beginning of 1992, we recorded a liability of $466 million for the accumulated transition obligation and a corresponding regulatory asset for anticipated recovery in utility rates. For additional details, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years. The measurement date for all CMS Energy plans is November 30 for 2006, 2005 and 2004. We changed our measurement date in 2004 from December 31 to November 30, which resulted in a $1 million cumulative effect of change in accounting for retirement benefits, net of tax benefit, as a decrease to earnings. We also increased the amount of accrued benefit cost on our Consolidated Balance Sheets by $2 million. The measurement date for the MCV Partnership's plan was December 31 for 2005 and 2004. 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): In September 2006, the FASB issued SFAS No. 158. This standard requires us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 requires us to recognize changes in the funded status of our plans in the year in which the changes occur. This standard also requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of this provision of the standard will have a material effect on our consolidated financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008. The following table recaps the incremental effect of applying SFAS No. 158 on individual line items on our Consolidated Balance Sheets. The adoption of SFAS No. 158 had no effect on our Consolidated Statements of CE-59 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Income (Loss) for the year ended December 31, 2006, or for any prior period presented, and it will not affect our operating results in future periods. Had we not been required to adopt SFAS No. 158 at December 31, 2006, we would have recognized an additional minimum liability pursuant to the provisions of SFAS No. 87. The effect of recognizing the additional minimum liability is included in the following table in the column labeled "Before Application of SFAS No. 158:"
BEFORE AFTER APPLICATION OF APPLICATION OF YEAR ENDED DECEMBER 31, 2006 SFAS NO. 158 ADJUSTMENT SFAS NO. 158 ---------------------------- -------------- ---------- -------------- (IN MILLIONS) Regulatory asset(a).............................. $ 470 $ 680 $ 1,150 Intangible asset................................. 46 (46) -- ------- ----- ------- Total assets..................................... 516 634 1,150 Liability for retirement benefits(b)............. (351) (643) (994) Regulatory liabilities -- Income taxes, net(c)... (459) (80) (539) Deferred income taxes............................ (941) 83 (858) ------- ----- ------- Total liabilities................................ (1,751) (640) (2,391) Accumulated other comprehensive income........... 2 6 8 ------- ----- ------- Total decrease in stockholders' equity........... 2 6 8 ======= ===== =======
-------- (a) Consumers recognized the cost of their minimum liability prior to application of SFAS No. 158 and the adjustment resulting from adoption of SFAS No. 158 as a regulatory asset under SFAS No. 71 based upon guidance from the MPSC. (b) Liabilities for retirement benefits include $993 million that are non- current and $1 million that is current at December 31, 2006. (C) The adjustment represents the Medicare D Subsidy tax benefit of implementing SFAS No. 158. Assumptions: The following tables recap the weighted-average assumptions used in our retirement benefits plans to determine benefit obligations and net periodic benefit cost: WEIGHTED AVERAGE FOR BENEFIT OBLIGATIONS:
PENSION & SERP OPEB --------------------- --------------------- YEARS ENDED DECEMBER 31 2006 2005 2004 2006 2005 2004 ----------------------- ----- ----- ----- ----- ----- ----- Discount rate........................... 5.65% 5.75% 6.00% 5.65% 5.75% 6.00% Expected long-term rate of return on plan assets(a)........................ 8.25% 8.50% 8.75% Union................................. 8.75% Non-Union............................. 6.00% Combined in 2005...................... 7.75% 8.00% Mortality table(b)...................... 2000 2000 1983 2000 2000 1983 Rate of compensation increase: Pension............................... 4.00% 4.00% 3.50% SERP.................................. 5.50% 5.50% 5.50%
CE-60 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) WEIGHTED AVERAGE FOR NET PERIODIC BENEFIT COST:
PENSION & SERP OPEB --------------------- --------------------- YEARS ENDED DECEMBER 31 2006 2005 2004 2006 2005 2004 ----------------------- ----- ----- ----- ----- ----- ----- Discount rate........................... 5.75% 5.75% 6.25% 5.75% 5.75% 6.25% Expected long-term rate of return on plan assets(a)........................ 8.50% 8.75% 8.75% Union................................. 8.75% Non-Union............................. 6.00% Combined in 2005...................... 8.00% 8.25% Mortality table(b)...................... 2000 2000 1983 2000 2000 1983 Rate of compensation increase: Pension............................... 4.00% 3.50% 3.25% SERP.................................. 5.50% 5.50% 5.50%
-------- (a) We determine our long-term rate of return by considering historical market returns, the current and future economic environment, the capital market principles of risk and return, and the expert opinions of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed annually for reasonableness and appropriateness. (b) Prior to 2005, we utilized the 1983 Group Annuity Mortality Table. Starting in 2005, we utilize the Combined Healthy RP-2000 Table from the 2000 Group Annuity Mortality Tables. Costs: The following tables recap the costs, other changes in plan assets and benefit obligations incurred in our retirement benefits plans:
PENSION & SERP ------------------- YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ----- (IN MILLIONS) Net periodic pension cost Service cost............................................... $ 47 $ 41 $ 36 Interest expense........................................... 81 76 77 Expected return on plan assets............................. (80) (89) (109) Amortization of: Net loss................................................ 41 33 14 Prior service cost...................................... 7 5 6 ---- ---- ----- Net periodic pension cost.................................. 96 66 24 Regulatory adjustment...................................... (11) -- -- ---- ---- ----- Net periodic pension cost after regulatory adjustment........ $ 85 $ 66 $ 24 ==== ==== =====
CE-61 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
OPEB ------------------ YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Net periodic OPEB cost Service cost................................................ $ 22 $ 21 $ 18 Interest expense............................................ 60 58 54 Expected return on plan assets.............................. (53) (49) (45) Amortization of: Net loss................................................. 20 20 11 Prior service credit..................................... (10) (9) (8) ---- ---- ---- Net periodic OPEB cost...................................... 39 41 30 Regulatory adjustment....................................... (2) -- -- ---- ---- ---- Net periodic OPEB cost after regulatory adjustment............ $ 37 $ 41 $ 30 ==== ==== ====
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from regulatory asset into net periodic benefits cost over the next fiscal year is $50 million. The estimated net loss and prior service credit for OPEB plans that will be amortized from regulatory asset into net periodic benefit cost over the next fiscal year is $12 million. Reconciliations: The following table reconciles the funding of our retirement benefits plans with our retirement benefits plans' liability:
PENSION PLAN SERP OPEB --------------- ----------- --------------- YEARS ENDED DECEMBER 31 2006 2005 2006 2005 2006 2005 ----------------------- ------ ------ ---- ---- ------ ------ (IN MILLIONS) Benefit obligation at beginning of period................................. $1,510 $1,328 $ 46 $ 40 $1,065 $1,013 Service cost............................. 49 42 1 1 22 21 Interest cost............................ 83 78 3 3 60 58 Plan amendment........................... -- 39 -- 1 -- (19) Actuarial loss (gain).................... 51 146 (1) 2 79 39 Benefits paid............................ (117) (123) (2) (1) (47) (47) ------ ------ ---- ---- ------ ------ Benefit obligation at end of period(a)... 1,576 1,510 47 46 1,179 1,065 ------ ------ ---- ---- ------ ------ Plan assets at fair value at beginning of period................................. 1,018 1,040 -- -- 655 598 Actual return on plan assets............. 126 101 -- -- 67 42 Company contribution..................... 13 -- 2 2 57 62 Actual benefits paid(b).................. (117) (123) (2) (2) (45) (47) ------ ------ ---- ---- ------ ------ Plan assets at fair value at end of period................................. 1,040 1,018 -- -- 734 655 ------ ------ ---- ---- ------ ------ Funded status at end of measurement period................................. (536) (492) (47) (46) (445) (410) Additional VEBA Contributions or Non-Trust Benefit Payments............... -- -- -- -- 14 15 ------ ------ ---- ---- ------ ------ Funded status at December 31(c).......... $ (536) $ (492) $(47) $(46) $ (431) $ (395) ====== ====== ==== ==== ====== ======
CE-62 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) -------- (a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy, which is tax-exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. The Medicare Part D annualized reduction in net OPEB cost was $27 million for 2006 and $23 million for 2005. The reduction includes $7 million for the year ended December 31, 2006 and $6 million for the year ended December 31, 2005 in capitalized OPEB costs. (b) We received $2 million in Medicare Part D Subsidy payments for the year ended December 31, 2006. (c) Of the $536 million funded status of the Pension Plan at December 31, 2006, $507 million is attributable to Consumers and of the $492 million funded status of the Pension Plan at December 31, 2005, $465 million is attributable to Consumers, based on allocation of expenses. The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans as of December 31, 2005 for all plans combined. (In accordance with SFAS No. 158, we recognized the underfunded status of our defined benefit postretirement plans as a liability on our consolidated balance sheets as of December 31, 2006.)
PENSION PLAN SERP OPEB ------------ ---- ------ YEAR ENDED DECEMBER 31 2005 2005 2005 ---------------------- ------------ ---- ------ (IN MILLIONS) Fair value of plan assets............................... $1,018 $ -- $ 655 Net benefit obligations................................. 1,510 46 1,065 ------ ---- ------ Funded status (plan assets less plan obligations)....... (492) (46) (410) Amounts not recognized Net actuarial loss.................................... 747 8 374 Prior service cost (credit)........................... 56 2 (109) Additional VEBA Contributions or Non-Trust Benefit Payments.............................................. -- -- 15 ------ ---- ------ Net amount recognized(a)................................ $ 311 $(36) $ (130) ====== ==== ======
-------------- (a) Of the $311 million net amount recognized, $293 million was attributable to Consumers based on the allocation of expenses. The following table provides a reconciliation of the amounts recognized on our Consolidated Balance Sheets as of December 31, 2005 for all plans combined:
PENSION PLAN SERP OPEB ------------ ---- ----- YEAR ENDED DECEMBER 31 2005 2005 2005 ---------------------- ------------ ---- ----- (IN MILLIONS) Prepaid benefit cost............................... $ 293 $ -- $ -- Accrued benefit cost............................... -- (36) (130) Additional minimum liability....................... (451) -- -- Intangible asset................................... 52 -- -- Regulatory asset................................... 399 -- -- ----- ---- ----- Net amount recognized.............................. $ 293 $(36) $(130) ===== ==== =====
CE-63 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table provides pension ABO in excess of plan assets:
YEARS ENDED DECEMBER 31 2006 2005 ----------------------- ------ ------ (IN MILLIONS) Pension ABO............................................... $1,240 $1,188 Fair value of pension plan assets......................... 1,040 1,018 ------ ------ Pension ABO in excess of pension plan assets.............. $ 200 $ 170 ====== ======
SFAS No. 158 Recognized: The following table recaps the amounts recognized in SFAS No. 158 regulatory assets and AOCI that have not been recognized as components of net periodic benefit cost. For additional details on regulatory assets, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation."
PENSION & SERP OPEB -------------- ---- YEAR ENDED DECEMBER 31 2006 2006 ---------------------- -------------- ---- (IN MILLIONS) Regulatory assets Net loss............................................ $676 $416 Prior service cost (credit)......................... 45 (99) AOCI Net loss (gain)..................................... 7 -- Prior service cost (credit)......................... 1 -- ---- ---- Total amounts recognized in regulatory assets and AOCI................................................ $729 $317 ==== ====
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
PENSION OPEB ----------- ----------- NOVEMBER 30 2006 2005 2006 2005 ----------- ---- ---- ---- ---- Asset Category: Fixed Income........................................... 28% 33% 37% 58% Equity Securities:..................................... 62% 65% 63% 40% CMS Energy Common Stock(a).......................... -- -- -- 1% Alternative Strategy................................ 10% 2% -- 1%
-------- (a) At November 30, 2006, there were no shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. At November 30, 2005, there were no shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. We contributed $55 million to our OPEB plan in 2006 and we plan to contribute $50 million to our OPEB plan in 2007. We contributed $13 million to our Pension Plan in 2006 and we plan to contribute $103 million to our Pension plan in 2007. We have established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor's 500 Index, with lesser allocations to the Standard & Poor's Mid Cap Index, the Small Cap Indexes and a Foreign Equity Index Fund. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. Annual liability CE-64 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation. We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers, and through direct contributions from the non- utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in a Standard & Poor's 500 Index fund. The fixed-income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed-income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees. SFAS No. 132(R) Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:
PENSION SERP OPEB(A) ------- ---- ------- (IN MILLIONS) 2007....................................................... $ 58 $2 $ 54 2008....................................................... 65 2 56 2009....................................................... 73 2 58 2010....................................................... 81 2 60 2011....................................................... 93 2 62 2012-2016.................................................. 652 9 333
-------------- (a) OPEB benefit payments are net of employee contributions and expected Medicare Part D prescription drug subsidy payments. The subsidies to be received are estimated to be $5 million for 2007, $6 million each year for 2008 through 2011 and $33 million combined for 2012 through 2016. 7: ASSET RETIREMENT OBLIGATIONS SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard requires companies to record the fair value of the cost to remove assets at the end of their useful life, if there is a legal obligation to remove them. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would increase by $25 million. If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, gas transmission and electric and gas distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates. FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS: This Interpretation clarified the term "conditional asset retirement obligation" as used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments qualifies as a conditional ARO, as defined by FASB Interpretation No. 47. CE-65 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following tables describe our assets that have legal obligations to be removed at the end of their useful life:
IN SERVICE ARO DESCRIPTION DATE LONG-LIVED ASSETS TRUST FUND --------------- ---------- ----------------- ---------- (IN MILLIONS) December 31, 2006 Palisades-decommission plant site... 1972 Palisades nuclear plant $598 Big Rock-decommission plant site.... 1962 Big Rock nuclear plant 4 JHCampbell intake/discharge water line.............................. 1980 Plant intake/discharge -- water line Closure of coal ash disposal areas.. Various Generating plants coal -- ash areas Closure of wells at gas storage fields............................ Various Gas storage fields -- Indoor gas services equipment relocations....................... Various Gas meters located -- inside structures Asbestos abatement.................. 1973 Electric and gas -- utility plant
ARO ARO LIABILITY CASH FLOW LIABILITY ARO DESCRIPTION 1/1/05(A) INCURRED SETTLED(B) ACCRETION REVISIONS 12/31/05 --------------- --------- -------- ---------- --------- --------- --------- (IN MILLIONS) Palisades-decommission............... $350 $-- $ -- $25 $-- $375 Big Rock-decommission................ 30 -- (42) 15 24 27 JHCampbell intake line............... -- -- -- -- -- -- Coal ash disposal areas.............. 54 -- (5) 5 -- 54 Wells at gas storage fields.......... 1 -- -- -- -- 1 Indoor gas services relocations...... 1 -- -- -- -- 1 Asbestos abatement................... 33 -- -- 3 -- 36 ---- --- ---- --- --- ---- Total................................ $469 $-- $(47) $48 $24 $494 ==== === ==== === === ====
ARO ARO LIABILITY CASH FLOW LIABILITY ARO DESCRIPTION 12/31/05 INCURRED SETTLED(B) ACCRETION REVISIONS 12/31/06 --------------- --------- -------- ---------- --------- --------- --------- (IN MILLIONS) Palisades-decommission............... $375 $-- $ -- $26 $-- $401 Big Rock-decommission................ 27 -- (28) 3 -- 2 JHCampbell intake line............... -- -- -- -- -- -- Coal ash disposal areas.............. 54 -- (2) 5 -- 57 Wells at gas storage fields.......... 1 -- -- -- -- 1 Indoor gas services relocations...... 1 -- -- -- -- 1 Asbestos abatement................... 36 -- (3) 2 -- 35 ---- --- ---- --- --- ---- Total................................ $494 $-- $(33) $36 $-- $497 ==== === ==== === === ====
-------------- (a) The ARO liability at January 1, 2005 in the preceding table reflects the ARO liability as if FASB Interpretation No. 47 had been in effect at that time, as required by the Interpretation. Our consolidated financial statements for that period do not reflect the asbestos abatement ARO. As required by SFAS No. 71, we accounted for the implementation of this Interpretation by recording a regulatory asset instead of a cumulative effect of a change in accounting principle. There was no effect on consolidated net income. (b) These cash payments are included in the Other current and non-current liabilities line in Net cash provided by operating activities in our Consolidated Statements of Cash Flows. In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and related accounting and ratemaking issues for MPSC-jurisdictional electric and gas utilities. In December 2005, the ALJ issued a Proposal for Decision recommending that the MPSC dismiss the proceeding. In March 2006, the MPSC CE-66 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) remanded the case to the ALJ for findings and recommendations. In August 2006, the ALJ issued a second Proposal for Decision that included recommendations that the MPSC: - adopt SFAS No. 143 and FERC Order No. 631 for accounting purposes but not for ratemaking purposes, - consider adopting standardized retirement units for certain accounts, - consider revising the method of determining cost of removal, and - withhold approving blanket regulatory asset and regulatory liability accounting treatment related to AROs, stating that modifications to the MPSC's Uniform System of Accounts should precede any such accounting approval. We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities. We cannot predict the outcome of the proceeding. 8: INCOME TAXES We join in the filing of a consolidated federal income tax return with CMS Energy and its subsidiaries. Income taxes generally are allocated based on each company's separate taxable income in accordance with the CMS Energy tax sharing agreement. We had tax related payables to CMS Energy of $31 million in 2006 and $128 million in 2005. We utilize deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service life of related properties. We use ITC to reduce current income taxes payable. AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2006, we had AMT credit carryforwards of $66 million that do not expire and tax loss carryforwards of $339 million that expire from 2023 through 2025. We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforwards prior to their expiration. In addition, we had general business credit carryforwards of $11 million, charitable contribution carryforwards of $7 million that expire from 2007 through 2009, and a capital loss carryforward of $31 million that expires in 2011, for which valuation allowances have been provided. The significant components of income tax expense (benefit) consisted of:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Current federal income taxes............................... $ 212 $ 176 $ 26 Current federal income tax benefit of operating loss carryforwards............................................ (8) (9) (11) Deferred federal income taxes.............................. (109) (201) 142 Deferred ITC, net.......................................... (4) (13) (5) ----- ----- ---- Income tax expense (benefit)............................... $ 91 $ (47) $152 ===== ===== ====
Current tax expense includes the settlement of income tax audits for prior years, as well as the provision for 2006 income taxes prior to the use of loss carryforwards. 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 our consolidated financial statements. Deferred tax assets and liabilities are classified as current or non-current 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. CE-67 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The principal components of deferred tax assets (liabilities) recognized on our Consolidated Balance Sheets are as follows:
DECEMBER 31 2006 2005 ----------- ---- ---- (IN MILLIONS) Property....................................................... $ (814) $ (748) Securitized costs.............................................. (177) (172) Gas inventories................................................ (168) (148) Employee benefits.............................................. 36 (61) Consolidated investments....................................... -- (54) SFAS No. 109 regulatory liability, net......................... 189 159 Nuclear decommissioning........................................ 57 59 Tax loss and credit carryforwards.............................. 209 60 Valuation allowances........................................... (15) -- Other, net..................................................... (175) (177) ------- ------- Net deferred tax liabilities................................... $ (858) $(1,082) ======= ======= Deferred tax liabilities....................................... $(2,272) $(2,093) Deferred tax assets, net of valuation allowance................ 1,414 1,011 ------- ------- Net deferred tax liabilities................................... $ (858) $(1,082) ======= =======
In June 2006, the IRS concluded its most recent audit of CMS Energy and its subsidiaries, and proposed changes to taxable income for the years ended December 31, 1987 through December 31, 2001. The proposed overall cumulative increase to taxable income related primarily to the disallowance of the simplified service cost method with respect to certain self-constructed utility assets. CMS Energy has accepted these proposed adjustments to taxable income, which have been allocated based upon Consumers' separate taxable income in accordance with CMS Energy's tax sharing agreement. We made a payment to CMS Energy for our share of these audit adjustments of $232 million, and reduced our 2006 income tax provision by $19 million, primarily for the restoration and utilization of previously written off income tax credits. CE-68 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The actual income tax expense (benefit) differs from the amount computed by applying the statutory federal tax rate of 35 percent to income (loss) before income taxes as follows:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ----- ----- ----- (IN MILLIONS) Income (loss) before cumulative effect of change in accounting principle..................................... $ 186 $ (96) $ 280 Income tax expense (benefit)............................... 91 (47) 152 ----- ----- ----- Income (loss) before income taxes.......................... 277 (143) 432 Statutory federal income tax rate.......................... x 35% x 35% x 35% ----- ----- ----- Expected income tax expense (benefit)...................... 97 (50) 151 Increase (decrease) in taxes from: Property differences..................................... 19 15 13 IRS Settlement/Credit Restoration........................ (19) -- -- Return to accrual adjustments............................ (7) 3 -- Medicare Part D exempt income............................ (10) (6) (5) ITC amortization......................................... (4) (4) (6) Expiration of general business credits................... -- 6 -- Valuation allowance...................................... 15 (9) 1 Other, net............................................... -- (2) (2) ----- ----- ----- Recorded income tax expense (benefit)...................... $ 91 $ (47) $ 152 ===== ===== ===== Effective tax rate......................................... 32.9% 32.9% 35.2% ===== ===== =====
During 2006, the valuation allowance increased by $15 million. In November 2006, we sold our interests in the MCV Partnership and the FMLP triggering a capital loss. A $12 million valuation allowance has been provided against the related deferred tax asset. Additionally, valuation allowances have been provided against charitable contributions and tax credits that are expected to expire unused. The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities at December 31, 2006 are adequate for all years. FIN 48, Accounting for Uncertainty in Income Taxes: In June 2006, the FASB issued FIN 48, effective for us January 2007. This interpretation provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management's best judgment, it is greater than 50 percent likely that the taxing authority will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return. Our policy is to include interest and penalties accrued, if any, on uncertain tax positions as part of the related tax liability on our consolidated balance sheet and as part of the income tax expense in our consolidated income statement. The impact from adopting FIN 48 should be recorded as a cumulative adjustment to the beginning retained earnings balance and a corresponding adjustment to a current or non-current tax liability. At this time, we are continuing to evaluate the impact of FIN 48 on our consolidated financial statements. 9: EXECUTIVE INCENTIVE COMPENSATION We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee directors based on their contributions to the successful management of the company. The Plan has a five-year term, expiring in May 2009. CE-69 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) All grants under the Plan for 2006 and 2005 were in the form of restricted stock. Restricted stock awards are outstanding shares to which the recipient has full voting and dividend rights and vest 100 percent after three years of continued employment. Restricted stock awards granted to officers in 2006, 2005, and 2004 are also subject to the achievement of specified levels of total shareholder return, including a comparison to a peer group of companies. All restricted stock awards are subject to forfeiture if employment terminates before vesting. However, if certain minimum service requirements are met, restricted shares may continue to vest upon retirement or disability and vest fully if control of CMS Energy changes, as defined by the Plan. In April 2006, we amended the Plan to allow awards not subject to achievement of total shareholder return to vest fully upon retirement, subject to the participant not accepting employment with a direct competitor. This modification did not have a material impact on our consolidated financial statements. The Plan also allows for stock options, stock appreciation rights, phantom shares, and performance units. None of which were granted in 2006 or 2005. Select participants may elect to receive all or a portion of their incentive payments under the Officer's Incentive Compensation Plan in the form of cash, shares of restricted common stock, shares of restricted stock units, or any combination of these. These participants may also receive awards of additional restricted common stock or restricted stock units, provided the total value of these additional grants does not exceed $2.5 million for any fiscal year. Shares awarded or subject to stock options, phantom shares, and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such awards to any participant exceed 250,000 shares in any fiscal year. We may issue awards of up to 4,382,800 shares of common stock under the Plan at December 31, 2006. Shares for which payment or exercise is in cash, as well as forfeited shares or stock options may be awarded or granted again under the Plan. The following table summarizes restricted stock activity under the Plan:
WEIGHTED-AVERAGE RESTRICTED STOCK NUMBER OF SHARES GRANT DATE FAIR VALUE ---------------- ---------------- --------------------- Nonvested at December 31, 2005..................... 1,154,316 $10.87 Granted.......................................... 460,880 $13.82 Vested........................................... (174,783) $ 7.32 Forfeited........................................ (18,413) $11.17 --------- ------ Nonvested at December 31, 2006..................... 1,422,000 $12.26
SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective. We expense the fair value over the required service period of the awards. As a result, we recognize all compensation expense for share-based awards with accelerated service provisions upon retirement by the period in which the employee becomes eligible to retire. The total fair value of shares vested was $2 million in 2006, $2 million in 2005, and $1 million in 2004. We calculate the fair value of restricted shares granted based on the price of our common stock on the grant date and expense the fair value over the required service period. Compensation expense related to restricted stock was $7 million in 2006, $3 million in 2005, and $2 million in 2004. The total related income tax benefit recognized in income was $2 million in 2006, $1 million in 2005, and $1 million of in 2004. At December 31, 2006, there was $8 million of total unrecognized compensation cost related to restricted stock. We expect to recognize this cost over a weighted-average period of 1.3 years. CE-70 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table summarizes stock option activity under the Plan:
WEIGHTED- OPTIONS WEIGHTED- AVERAGE OUTSTANDING, AVERAGE REMAINING AGGREGATE FULLY VESTED, EXERCISE CONTRACTUAL INTRINSIC STOCK OPTIONS AND EXERCISABLE PRICE TERM VALUE ------------- --------------- --------- ----------- ------------- (IN MILLIONS) Outstanding at December 31, 2005.......... 1,714,787 $18.13 5.9 years $(6) Granted................................. -- -- Exercised............................... (61,095) 7.07 Cancelled or Expired.................... (51,908) 30.09 Outstanding at December 31, 2006.......... 1,601,784 $18.16 5.0 years $(2)
Stock options give the holder the right to purchase common stock at a price equal to the fair value of our common stock on the grant date. Stock options are exercisable upon grant, and expire up to 10 years and one month from the grant date. We issue new shares when participants exercise stock options. The total intrinsic value of stock options exercised was $1 million in 2006, 2005, and 2004. Cash received from exercise of these stock options was less than $1 million in 2006. Since we have utilized tax loss carryforwards, we were not able to realize the excess tax benefits upon exercise of stock options. Therefore, we did not recognize the related excess tax benefits in equity. 10: LEASES We lease various assets, including service vehicles, railcars, construction equipment, office furniture, and buildings. We purchase renewable energy under certain power purchase agreements, as required by the MPSC. In accordance with SFAS No. 13, we account for these power purchase agreements as capital and operating leases. Operating leases for coal-carrying railcars have lease terms expiring over the next 15 years. These leases contain fair market value extension and buyout provisions, with some providing for predetermined extension period rentals. Capital leases for our vehicle fleet operations have a maximum term of 120 months and TRAC end-of-life provisions. The capital lease for furniture terminates in 2013, but provides for an early buyout in April 2008. Power purchase agreements range from 7 to 20 years. Most of our power purchase agreements contain options at the end of the initial contract term to renew the agreement annually. We are authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. The following table summarizes our capital and operating lease expenses:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Capital lease expense.......................................... $15 $14 $13 Operating lease expense........................................ 19 17 13
CE-71 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Minimum annual rental commitments under our non-cancelable leases at December 31, 2006 are:
CAPITAL OPERATING LEASES LEASES ------- --------- (IN MILLIONS) 2007........................................................... $13 $ 23 2008........................................................... 12 22 2009........................................................... 11 19 2010........................................................... 9 17 2011........................................................... 7 17 2012 and thereafter............................................ 29 61 --- ---- Total minimum lease payments................................... 81 $159 ==== Less imputed interest.......................................... 26 --- Present value of net minimum lease payments.................... 55 Less current portion........................................... 13 --- Non-current portion............................................ $42
11: PROPERTY, PLANT, AND EQUIPMENT The following table is a summary of our Property, plant and equipment:
ESTIMATED DEPRECIABLE DECEMBER 31 LIFE IN YEARS 2006 2005 ----------- ------------- ------ ------ (IN MILLIONS) Electric: Generation........................................... 13-85 $3,573 $3,487 Distribution......................................... 12-75 4,425 4,226 Other................................................ 7-40 421 404 Capital leases(a).................................... 85 87 Gas: Underground storage facilities(b).................... 30-65 263 262 Transmission......................................... 15-75 465 416 Distribution......................................... 40-75 2,216 2,141 Other................................................ 7-50 300 306 Capital leases(a).................................... 29 26 Other: MCV Facility(c)................................. 5-35 -- 211 Non-utility property................................. 7-71 15 15 Construction work-in-progress........................ 639 509 Other................................................ -- 1 Less accumulated depreciation, depletion, and amortization(d)...................................... 4,983 4,804 ------ ------ Net property, plant, and equipment(e)(f)............... $7,448 $7,287 ====== ======
-------------- (a) Capital leases presented in this table are gross amounts. Accumulated amortization of capital leases was $59 million at December 31, 2006 and $54 million at December 31, 2005. Capital lease additions were $7 million and capital lease retirements and adjustments were $6 million during 2006. Capital lease additions were $12 million and capital lease retirements and adjustments were $7 million during 2005. (b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2006 and December 31, 2005, which is not subject to depreciation. CE-72 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (c) In November 2006, we sold 100 percent of our ownership interest of MCV GP II (the successor to CMS Midland, Inc.) and 100 percent of our ownership of the stock of CMS Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments. For additional details on our sale of the MCV Partnership and the MCV facility, see Note 2, Asset Sales and Impairment Charges. (d) At December 31, 2006, accumulated depreciation, depletion, and amortization included $4.982 billion from our public utility plant and $1 million related to our non-utility plant assets. At December 31, 2005, accumulated depreciation, depletion, and amortization included $4.803 billion from our public utility plant and $1 million related to our non- utility plant assets. (e) At December 31, 2006, public utility plant additions were $470 million and public utility plant retirements, including other plant adjustments, were $82 million. At December 31, 2005, public utility plant additions were $450 million and public utility plant retirements, including other plant adjustments, were $64 million. (f) Included in net property, plant and equipment are intangible assets primarily related to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization lives for software development costs range from seven to twelve years. The estimated amortization life for leasehold improvements is the life of the lease. Other intangible amortization lives range from 50 to 75 years. The following tables summarize our intangible assets:
INTANGIBLE ACCUMULATED ASSET, DECEMBER 31, 2006 GROSS COST AMORTIZATION NET ----------------- ---------- ------------ ---------- (IN MILLIONS) Software development................................ $204 $153 $ 51 Rights of way....................................... 114 31 83 Leasehold improvements.............................. 19 15 4 Franchises and consents............................. 19 10 9 Other intangibles................................... 18 13 5 ---- ---- ---- Total............................................... $374 $222 $152 ==== ==== ====
INTANGIBLE ACCUMULATED ASSET, DECEMBER 31, 2005 GROSS COST AMORTIZATION NET ----------------- ---------- ------------ ---------- (IN MILLIONS) Software development................................ $200 $135 $ 65 Rights of way....................................... 102 29 73 Leasehold improvements.............................. 19 14 5 Franchises and consents............................. 19 9 10 Other intangibles................................... 18 13 5 ---- ---- ---- Total............................................... $358 $200 $158 ==== ==== ====
Pre-tax amortization expense related to these intangible assets was $22 million for the year ended December 31, 2006, $19 million for the year ended December 31, 2005, and $19 million for the year ended December 31, 2004. Intangible assets amortization is forecasted to range from $13 million to $23 million per year over the next five years. CE-73 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 12: JOINTLY OWNED REGULATED UTILITY FACILITIES We have investments in jointly owned regulated utility facilities as shown in the following table:
NET ACCUMULATED CONSTRUCTION INVEST- DEPRECIA- WORK IN MENT(A) TION PROGRESS OWNERSHIP ----------- ----------- ------------- DECEMBER 31 SHARE 2006 2005 2006 2005 2006 2005 ----------- --------- ---- ---- ---- ---- ---- ---- (percent) (In Millions) Campbell Unit 3....................... 93.3 $262 $270 $370 $354 $353 $258 Ludington............................. 51.0 68 72 95 92 1 1 Distribution.......................... Various 98 100 47 45 4 9
-------- (a) Net investment is the amount of utility plant in service less accumulated depreciation. The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant's undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities. 13: REPORTABLE SEGMENTS Our reportable segments are strategic business units organized and managed by the nature of the products and services each provides. We evaluate performance based upon the net income of each segment. Our two principal segments are electric utility and gas utility. The electric utility segment consists of regulated activities associated with the generation and distribution of electricity in the state of Michigan. The gas utility segment consists of regulated activities associated with the transportation, storage, and distribution of natural gas in the state of Michigan. Accounting policies of our segments are the same as we describe in the summary of significant accounting policies. Our consolidated financial statements reflect the assets, liabilities, revenues, and expenses directly related to the electric and gas segment where it is appropriate. We allocate accounts between the electric and gas segments where common accounts are attributable to both segments. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, other operation and maintenance expense, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue. Pension provisions are allocated based on labor dollars. We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income (loss) available to common stockholder by segment. The "Other" segment includes our consolidated special purpose entity for the sale of trade receivables, the MCV Partnership and the FMLP. The following table shows our financial information by reportable segment:
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Operating Revenues Electric............................................. $ 3,302 $ 2,701 $ 2,586 Gas.................................................. 2,374 2,483 2,081 Other................................................ 45 48 44 ------- ------- ------- $ 5,721 $ 5,232 $ 4,711 ======= ======= ======= Earnings from Equity Method Investees Electric............................................. $ 1 $ -- $ -- Other................................................ -- 1 1 ------- ------- ------- $ 1 $ 1 $ 1 ======= ======= =======
CE-74 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ---- ---- ---- (IN MILLIONS) Depreciation, Depletion and Amortization Electric............................................. $ 380 $ 292 $ 189 Gas.................................................. 122 117 112 Other................................................ 25 75 90 ------- ------- ------- $ 527 $ 484 $ 391 ======= ======= ======= Interest Charges Electric............................................. $ 167 $ 133 $ 204 Gas.................................................. 73 68 65 Other................................................ 49 71 97 ------- ------- ------- $ 289 $ 272 $ 366 ======= ======= ======= Income Tax (Benefit) Expense Electric............................................. $ 95 $ 85 $ 120 Gas.................................................. 18 39 40 Other................................................ (22) (171) (8) ------- ------- ------- $ 91 $ (47) $ 152 ======= ======= ======= Net Income (Loss) Available to Common Stockholder Electric............................................. $ 199 $ 153 $ 222 Gas.................................................. 37 48 71 Other................................................ (52) (299) (16) ------- ------- ------- $ 184 $ (98) $ 277 ======= ======= ======= Investments in Equity Method Investees Electric............................................. $ 5 $ 3 $ 3 Other................................................ -- 4 16 ------- ------- ------- $ 5 $ 7 $ 19 ======= ======= ======= Total Assets Electric(a).......................................... $ 8,516 $ 7,755 $ 7,289 Gas(a)............................................... 3,950 3,609 3,187 Other................................................ 379 1,814 2,335 ------- ------- ------- $12,845 $13,178 $12,811 ======= ======= ======= Capital Expenditures(b) Electric............................................. $ 462 $ 384 $ 360 Gas.................................................. 172 168 137 Other................................................ 19 32 21 ------- ------- ------- $ 653 $ 584 $ 518 ======= ======= =======
-------------- (a) Amounts include a portion of our other common assets attributable to both the electric and gas utility businesses. (b) Amounts include electric restructuring implementation plan, purchase of nuclear fuel, and capital lease additions. Amounts also include a portion of capital expenditures for plant and equipment attributable to both the electric and gas utility businesses. CE-75 CONSUMERS ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 14: CONSOLIDATION OF VARIABLE INTEREST ENTITIES Until their sale in November 2006, we had a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Prior to their sale, we were the primary beneficiary of both the MCV Partnership and the FMLP because Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement and Consumers, through its ownership interest in the FMLP, held a 35 percent lessor interest in the MCV Facility. Therefore, we consolidated these partnerships into our consolidated financial statements as of and for the year ended December 31, 2005. Upon the sale of our interests in the MCV Partnership and the FMLP, we are no longer the primary beneficiary of these entities and the entities were deconsolidated. For additional details on the sale of our interests in the MCV Partnership and the FMLP, see Note 2, Asset Sales and Impairment Charges. These partnerships had third-party obligations totaling $482 million at December 31, 2005. Property, plant, and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005. The creditors of these partnerships did not have recourse to the general credit of Consumers. At December 31, 2005, the MCV Partnership had total assets of $1.318 billion and a net loss of $917 million for the year. 15: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
2006 ------------------------------------------ QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31(A) -------------- -------- ------- -------- ---------- IN MILLIONS Operating revenue.......................... $1,782 $1,138 $1,191 $1,610 Operating income (loss).................... 7 78 239 (43) Net income................................. 10 36 99 41 Preferred stock dividends.................. -- 1 -- 1 Net income available to common stockholder.............................. 10 35 99 40
2005 --------------------------------------- QUARTERS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------------- -------- ------- -------- ------- IN MILLIONS Operating revenue........................... $1,632 $1,016 $1,025 $1,559 Operating income (loss)..................... 416 86 (865) (9) Net income (loss)........................... 157 33 (276) (10) Preferred stock dividends................... -- 1 -- 1 Net income (loss) available to common stockholder............................... 157 32 (276) (11)
-------------- (a) The quarter ended December 31, 2006 includes a $41 million net loss on the sale of our investment in the MCV Partnership including the negative impact of the associated impairment charge. For further information see Note 2, Asset Sales and Impairment Charges. CE-76 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholder of Consumers Energy Company We have audited the accompanying consolidated balance sheets of Consumers Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) as of December 31, 2006 and 2005, and the related consolidated statements of income (loss), common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements, and schedule based on our audits. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a former 49% owned variable interest entity which has been consolidated through the date of sale, November 21, 2006 (Note 2), which statements reflect total assets constituting 10.0% in 2005, and total revenues constituting 9.5% in 2006, 11.3% in 2005 and 13.8% in 2004 of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for the periods indicated above for Midland Cogeneration Venture Limited Partnership, is based solely on the report of the other auditors. 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 and the report of other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Consumers Energy Company at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 6 to the consolidated financial statements, in 2006, the Company adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106 and 132(R)." As discussed in Note 9 to the consolidated financial statements, in 2006, the Company adopted FASB Statement of Financial Accounting Standards No. 123(R) "Share-Based Payment." In addition, as discussed in Note 7 to the consolidated financial statements, in 2005 the Company adopted FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." As discussed in Note 6 to the consolidated financial statements, in 2004 the Company changed its measurement date for all Consumers Energy Company pension and postretirement plans. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Consumers Energy Company's internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2007, expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Detroit, Michigan February 21, 2007 CE-77 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners and the Management Committee of Midland Cogeneration Venture Limited Partnership: In our opinion, the accompanying balance sheets and the related statements of operations, of partners' equity (deficit) and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and December 31, 2005, and the results of its operations and its cash flows for the period ended November 21, 2006 and the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP February 19, 2007 CE-78 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE CMS ENERGY On November 30, 2006, CMS Energy dismissed Ernst & Young LLP ("Ernst & Young") as its independent registered public accounting firm. The decision to dismiss Ernst & Young was recommended and approved by the Audit Committee of the Board of Directors of CMS Energy (the "Audit Committee") and was the result of a competitive bidding process conducted in the ordinary course of business. Ernst & Young continued as the auditors for the consolidated financial statements of CMS Energy for the fiscal year ended December 31, 2006. During CMS Energy's two most recent fiscal years ended December 31, 2006 and December 31, 2005 and the subsequent interim period through February 23, 2007, there were no disagreements with Ernst & Young on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures which disagreement(s), if not resolved to the satisfaction of Ernst & Young, would have caused them to make reference to the subject matter of the disagreement(s) in connection with their reports on CMS Energy's consolidated financial statements for such years. During CMS Energy's two most recent fiscal years ended December 31, 2006 and December 31, 2005 and the subsequent interim period through February 23, 2007, there have been no "reportable events" as defined in Regulation S-K, Item 304(a)(1)(v), except for a material weakness at CMS Energy regarding internal controls over financial reporting relating to accounting for income taxes as of December 31, 2005, which has been remediated. CONSUMERS On November 30, 2006, Consumers dismissed Ernst & Young LLP ("Ernst & Young") as its independent registered public accounting firm. The decision to dismiss Ernst & Young was recommended and approved by the Audit Committee of the Board of Directors of Consumers (the "Audit Committee") and was the result of a competitive bidding process conducted in the ordinary course of business. Ernst & Young continued as the auditors for the consolidated financial statements of Consumers for the fiscal year ended December 31, 2006. During Consumers' two most recent fiscal years ended December 31, 2006 and December 31, 2005 and the subsequent interim period through February 23, 2007, there were no disagreements with Ernst & Young on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures which disagreement(s), if not resolved to the satisfaction of Ernst & Young, would have caused them to make reference to the subject matter of the disagreement(s) in connection with their reports on Consumers' consolidated financial statements for such years. During Consumers' two most recent fiscal years ended December 31, 2006 and December 31, 2005 and the subsequent interim period through February 23, 2007, there have been no "reportable events" as defined in Regulation S-K, Item 304(a)(1)(v). ITEM 9A. CMS ENERGY'S CONTROLS AND PROCEDURES CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES: Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d- 15(e) under the Exchange Act). Based on such evaluation, CMS Energy's CEO and CFO have concluded that its disclosure controls and procedures were effective as of December 31, 2006. MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: CMS Energy's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a- 15(f). CMS Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and includes policies and procedures that: - pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of CMS Energy; CO-1 - provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America, and that receipts and expenditures of CMS Energy are being made only in accordance with authorizations of management and directors of CMS Energy; and - provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CMS Energy's assets that could have a material effect on its financial statements. Management, including its CEO and CFO, does not expect that its internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates. Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2006. In making this evaluation, management used the criteria set forth in the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, CMS Energy's management concluded that its internal control over financial reporting was effective as of December 31, 2006. CMS Energy's management's assessment of the effectiveness of CMS Energy's internal control over financial reporting as of December 31, 2006 has been audited by Ernst & Young LLP, an independent registered public accounting firm, which audited the consolidated financial statements of CMS Energy included in this Form 10-K. Ernst & Young LLP's attestation report on CMS Energy's management's assessment of internal control over financial reporting is provided elsewhere in this Item 9A. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING: There have been no changes in CMS Energy's internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting. CO-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders of CMS Energy Corporation We have audited management's assessment, included in the accompanying MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that CMS Energy Corporation (a Michigan Corporation) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CMS Energy Corporation'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. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, 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 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assessment that CMS Energy Corporation maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, CMS Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CMS Energy Corporation as of December 31, 2006 and 2005, and the related consolidated statements of income (loss), common stockholders' equity, and cash flows for the each of the three years in the period ended December 31, 2006 of CMS Energy Corporation and our report dated February 21, 2007 expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Detroit, Michigan February 21, 2007 CO-3 ITEM 9A. CONSUMERS ENERGY'S CONTROLS AND PROCEDURES CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES: Under the supervision and with the participation of management, including its CEO and CFO, Consumers Energy conducted an evaluation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on such evaluation, Consumers Energy's CEO and CFO have concluded that its disclosure controls and procedures were effective as of December 31, 2006. MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: Consumers Energy's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a- 15(f). Consumers Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and includes policies and procedures that: - pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Consumers Energy; - provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America, and that receipts and expenditures of Consumers Energy are being made only in accordance with authorizations of management and directors of Consumers Energy; and - provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Consumers' assets that could have a material effect on its financial statements. Management, including its CEO and CFO, does not expect that its internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates. Under the supervision and with the participation of management, including its CEO and CFO, Consumers Energy conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2006. In making this evaluation, management used the criteria set forth in the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, Consumers' management concluded that its internal control over financial reporting was effective as of December 31, 2006. Consumers Energy's management's assessment of the effectiveness of Consumers Energy's internal control over financial reporting as of December 31, 2006 has been audited by Ernst & Young LLP, an independent registered public accounting firm, which audited the consolidated financial statements of Consumers Energy included in this Form 10-K. Ernst & Young LLP's attestation report on Consumers Energy's management's assessment of internal control over financial reporting is provided elsewhere in this Item 9A. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING: There have been no changes in Consumers Energy's internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting. CO-4 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholder of Consumers Energy Company We have audited management's assessment, included in the accompanying MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that Consumers Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Consumers Energy 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. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of 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, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, 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 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assessment that Consumers Energy Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also in our opinion, Consumers Energy Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Consumers Energy Company as of December 31, 2006 and 2005, and the related consolidated statements of income (loss), common stockholder's equity, and cash flows for the each of the three years in the period ended December 31, 2006 of Consumers Energy Company and our report dated February 21, 2007 expressed an unqualified opinion thereon. /s/ Ernst & Young LLP Detroit, Michigan February 21, 2007 CO-5 ITEM 9B. OTHER INFORMATION CMS ENERGY None. CONSUMERS None. CO-6 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE CMS ENERGY Information that is required in Item 10 regarding directors, executive officers and corporate governance is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. CONSUMERS Information that is required in Item 10 regarding Consumers' directors, executive officers and corporate governance is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. ITEM 11. EXECUTIVE COMPENSATION Information that is required in Item 11 regarding executive compensation of CMS Energy's and Consumers' executive officers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. The following disclosure describes 2007 compensation issues for officers. OFFICER INCENTIVE COMPENSATION PLAN On February 20, 2007, the Compensation and Human Resources Committees (the "C&HR Committees") of the Boards of Directors of CMS Energy and Consumers (the "Boards") approved the payout of cash bonuses under the 2006 Annual Officer Incentive Compensation Plan as well as the material terms of the 2007 Annual Officer Incentive Compensation Plan (the "Plan"), including the corporate performance goals thereunder. The Plan includes the material terms detailed below, although the specific target levels for the corporate performance goals vary from year to year. CORPORATE PERFORMANCE GOALS: The composite plan performance factor will depend on corporate performance in two areas: (1) the adjusted net income per outstanding CMS Energy common share ("Plan EPS"); and (2) the corporate free cash flow of CMS Energy ("CFCF"). Plan EPS performance shall constitute one-half of the composite plan performance factor and CFCF performance shall constitute one-half of the composite plan performance factor. There will be a payout under the Plan if either a Plan EPS performance factor of at least 94.1 percent of the target Plan EPS or a CFCF performance factor of at least 92 percent of the target CFCF is achieved. Even if only one but not both of these target minimums is achieved, a partial payout would result. The composite plan performance factor to be used for payouts will be capped at a maximum of 200 percent. Annual awards under the Plan to Consumers' officers may be reduced by 25 percent in the event that there is no payout to non-officer, non-union employees under a separate Consumers' employee incentive plan. ANNUAL AWARD FORMULA: Annual awards for each eligible officer will be based upon a standard award percentage of the officer's base salary as in effect on January 1 of the performance year. The maximum amount that can be awarded under the Plan for any Internal Revenue Code Section 162(m) employee will not exceed $2.5 million in any one performance year. Annual awards for officers will be calculated and made as follows: Individual Award = Base Salary times Standard Award % times Performance Factor %. The standard award percentages for officers are based on individual salary grade levels and remain unchanged from the 2006 plan. PAYMENT OF ANNUAL AWARDS: All annual awards for a performance year will be paid in cash no later than March 15th of the calendar year following the performance year provided that they first have been reviewed and approved by the C&HR Committees, and provided further that the annual award for a particular performance year has not been deferred voluntarily. The amounts required by law to be withheld for income and employment taxes will be deducted from the annual award payments. All annual awards become the obligation of the company on whose payroll the employee is enrolled at the time the C&HR Committees make the annual award. CO-7 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS CMS ENERGY Information that is required in Item 12 regarding securities authorized for issuance under equity compensation plans and security ownership of certain beneficial owners and management is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. CONSUMERS Information that is required in Item 12 regarding securities authorized for issuance under equity compensation plans and security ownership of certain beneficial owners and management of Consumers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE CMS ENERGY Information that is required in Item 13 regarding certain relationships and related transactions, and director independence is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. CONSUMERS Information that is required in Item 13 regarding certain relationships and related transactions, and director independence regarding Consumers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES CMS ENERGY Information that is required in Item 14 regarding principal accountant fees and services is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. CONSUMERS Information that is required in Item 14 regarding principal accountant fees and services relating to Consumers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)(1) Financial Statements and Reports of Independent Public Accountants for CMS Energy and Consumers are included in each company's ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA and are incorporated by reference herein. CO-8 (a)(2) Index to Financial Statement Schedules.
PAGE ------- Schedule I Condensed Financial Information of Registrant CMS Energy-Parent Company Condensed Statements of Income (Loss).............. CO-14 Statements of Cash Flows........................... CO-15 Condensed Balance Sheets........................... CO-16 Notes to Condensed Financial Statements............ CO-17 Schedule II Valuation and Qualifying Accounts and Reserves CMS Energy Corporation............................... CO-19 Consumers Energy Company............................. CO-19 Report of Independent Registered Public Accounting Firm CMS Energy Corporation............................... CMS-105 Consumers Energy Company............................. CE-77
Schedules other than those listed above are omitted because they are either not required, not applicable or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules filed have been omitted because the information is not applicable. (a)(3) Exhibits for CMS Energy and Consumers are listed after Item 15(b) below and are incorporated by reference herein. (b) Exhibits, including those incorporated by reference. CO-9 CMS ENERGY'S AND CONSUMERS' EXHIBITS
PREVIOUSLY FILED -------------------------- WITH FILE AS EXHIBIT EXHIBITS NUMBER NUMBER DESCRIPTION -------- --------- ---------- ----------- (3)(a) 1-9513 (99)(a) -- Restated Articles of Incorporation of CMS Energy (Form 8-K filed June 3, 2004) (3)(b) 1-9513 (3)(a) -- Bylaws of CMS Energy (Form 8-K filed October 6, 2004) (3)(c) 1-5611 3(c) -- Restated Articles of Incorporation dated May 26, 2000, of Consumers (2000 Form 10-K) (3)(d) 1-5611 (3)(b) -- Bylaws of Consumers (Form 8-K filed October 6, 2004) (4)(a) 2-65973 (b)(1)-4 -- Indenture dated as of September 1, 1945, between Consumers and Chemical Bank (successor to Manufacturers Hanover Trust Company), as Trustee, including therein indentures supplemental thereto through the Forty-third Supplemental Indenture dated as of May 1, 1979 -- Indentures Supplemental thereto: 1-5611 (4)(a) -- 70th dated as of 2/01/98 (1997 Form 10-K) 1-5611 (4)(a) -- 71st dated as of 3/06/98 (1997 Form 10-K) 1-5611 (4)(b) -- 75th dated as of 10/1/99 (1999 Form 10-K) 1-5611 (4)(d) -- 77th dated as of 10/1/99 (1999 Form 10-K) 1-5611 (4)(d) -- 90th dated as of 4/30/03 (1st qtr. 2003 Form 10-Q) 1-5611 (4)(a) -- 91st dated as of 5/23/03 (3rd qtr. 2003 Form 10-Q) 1-5611 (4)(b) -- 92nd dated as of 8/26/03 (3rd qtr. 2003 Form 10-Q) 1-5611 (4)(a) -- 96th dated as of 8/17/04 (Form 8-K filed August 20, 2004) 333-120611 (4)(e)(xv) -- 97th dated as of 9/1/04 (Consumers Form S-3 dated November 18, 2004) 1-5611 4.4 -- 98th dated as of 12/13/04 (Form 8-K filed December 13, 2004) 1-5611 (4)(a)(i) -- 99th dated as of 1/20/05 (2004 Form 10-K) 1-5611 4.2 -- 100th dated as of 3/24/05 (Form 8-K filed March 30, 2005) 1-5611 (4)(a) -- 101st dated as of 4/1/05 (1st qtr 2005 Form 10-Q) 1-5611 4.2 -- 102nd dated as of 4/13/05 (Form 8-K filed April 13, 2005) 1-5611 4.2 -- 104th dated as of 8/11/05 (Form 8-K filed August 11, 2005) (4)(b) 1-5611 (4)(b) -- Indenture dated as of January 1, 1996 between Consumers and The Bank of New York, as Trustee (1995 Form 10-K) (4)(c) 1-5611 (4)(c) -- Indenture dated as of February 1, 1998 between Consumers and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee (1997 Form 10-K) (4)(d) 33-47629 (4)(a) -- Indenture dated as of September 15, 1992 between CMS Energy and NBD Bank, as Trustee (Form S-3 filed May 1, 1992) Indentures Supplemental thereto: 1-9513 (4)(d)(i) -- 7th dated as of 1/25/99 (1998 Form 10-K) 333-48276 (4) -- 10th dated as of 10/12/00 (Form S-3 filed October 19, 2000) 333-58686 (4)(a) -- 11th dated as of 3/29/01 (Form S-8 filed April 11, 2001) 333-51932 (4)(a) -- 12th dated as of 7/02/01 (Form POS AM filed August 3, 2001) 1-9513 (4)(d)(i) -- 15th dated as of 9/29/04 (2004 Form 10-K) 1-9513 (4)(d)(ii) -- 16th dated as of 12/16/04 (2004 Form 10-K) 1-9513 4.2 -- 17th dated as of 12/13/04 (Form 8-K filed December 13, 2004) 1-9513 4.2 -- 18th dated as of 1/19/05 (Form 8-K filed January 20, 2005) 1-9513 4.2 -- 19th dated as of 12/13/05 (Form 8-K filed December 15, 2005) (4)(e) 1-9513 (4a) -- Indenture dated as of June 1, 1997, between CMS Energy and The Bank of New York, as trustee (Form 8-K filed July 1, 1997)
CO-10
PREVIOUSLY FILED -------------------------- WITH FILE AS EXHIBIT EXHIBITS NUMBER NUMBER DESCRIPTION -------- --------- ---------- ----------- -- Indentures Supplemental thereto: 1-9513 (4)(b) -- 1st dated as of 6/20/97 (Form 8-K filed July 1, 1997) (4)(f) 1-9513 (4)(i) -- Certificate of Designation of 4.50% Cumulative Convertible Preferred Stock dated as of December 2, 2003 (2003 Form 10-K) (10)(a) 333-125553 (4)(j) -- $300 million Sixth Amended and Restated Credit Agreement dated as of May 18, 2005 among CMS Energy, Enterprises, the Banks, and the Administrative Agent and Collateral Agent, all defined therein (Form S-3 filed June 6, 2005) (10)(b) 333-125553 (4)(k) -- Reaffirmation of grant of a security interest dated as of May 18, 2005 among CMS Energy, CMS Enterprises, and the Administrative Agent and Collateral Agent, as defined therein (Form S-3 filed June 6, 2005) (10)(c) 1-9513 (4)(l) -- Cash Collateral Agreement dated as of August 3, 2004 made by CMS Energy to the Administrative Agent for the lenders and Collateral Agent, as defined therein (2004 Form 10-K) (10)(d) 1-5611 (4)(b) -- $500 million Third Amended and Restated Credit Agreement dated as of May 18, 2005 among Consumers, the Banks, the Administrative Agent, the Syndication Agent and the Co-Documentation Agents, all as defined therein (2nd qtr 2005 Form 10-Q) -- Indenture Supplemental thereto: 1-5611 (10)(e) -- 103rd Supplemental Indenture to the Indenture dated as of September 1, 1945 between Consumers and Chemical Bank (successor to Manufacturers Hanover Trust Company), as Trustee (2005 Form 10- K) (10)(e) 1-5611 (10)(a) -- $300 million Credit Agreement dated as of March 31, 2006 among Consumers, the Banks, the Administrative Agent, the Syndication Agent, the Co-Documentation Agents, and the Co-Managing Agents, all as defined therein (1st qtr 2006 Form 10-Q) (10)(f) -- CMS Energy's Performance Incentive Stock Plan effective February 3, 1988, as amended June 1, 2004 and as further amended effective February 20, 2007 (10)(g) 1-9513 (10)(m) -- CMS Deferred Salary Savings Plan effective January 1, 1994 (1993 Form 10-K) (10)(h) -- Annual Officer Incentive Compensation Plan for CMS Energy Corporation and its Subsidiaries effective January 1, 2006 (10)(i) 1-9513 (10)(h) -- Supplemental Executive Retirement Plan for Employees of CMS Energy/Consumers Energy Company effective January 1, 1982, as amended December 3, 1999 (1999 Form 10-K) (10)(j) 1-9513 (10)(v) -- Amended and Restated Investor Partner Tax Indemnification Agreement dated as of June 1, 1990 among Investor Partners, CMS Midland as Indemnitor and CMS Energy as Guarantor (1990 Form 10-K) (10)(k) 1-9513 (19)(d)* -- Environmental Agreement dated as of June 1, 1990 made by CMS Energy to The Connecticut National Bank and Others (1990 Form 10-K) (10)(l) 1-9513 (10)(z)* -- Indemnity Agreement dated as of June 1, 1990 made by CMS Energy to Midland Cogeneration Venture Limited Partnership (1990 Form 10-K)
CO-11
PREVIOUSLY FILED -------------------------- WITH FILE AS EXHIBIT EXHIBITS NUMBER NUMBER DESCRIPTION -------- --------- ---------- ----------- (10)(m) 1-9513 (10)(aa)* -- Environmental Agreement dated as of June 1, 1990 made by CMS Energy to United States Trust Company of New York, Meridian Trust Company, each Subordinated Collateral Trust Trustee and Holders from time to time of Senior Bonds and Subordinated Bonds and Participants from time to time in Senior Bonds and Subordinated Bonds (1990 Form 10-K) (10)(n) 33-3797 10.4 -- Power Purchase Agreement dated as of July 17, 1986 between MCV Partnership and Consumers (MCV Partnership) Amendments thereto: 33-37977 10.5 -- Amendment No. 1 dated September 10, 1987 (MCV Partnership) 33-37977 10.6 -- Amendment No. 2 dated March 18, 1988 (MCV Partnership) 33-37977 10.7 -- Amendment No. 3 dated August 28, 1989 (MCV Partnership) 33-37977 10.8 -- Amendment No. 4A dated May 25, 1989 (MCV Partnership) (10)(o) 1-5611 (10)(y) -- Unwind Agreement dated as of December 10, 1991 by and among CMS Energy, Midland Group, Ltd., Consumers, CMS Midland, Inc., MEC Development Corp. and CMS Midland Holdings Company (1991 Form 10-K) (10)(p) 1-5611 (10)(z) -- Stipulated AGE Release Amount Payment Agreement dated as of June 1, 1990, among CMS Energy, Consumers and The Dow Chemical Company (1991 Form 10-K) (10)(q) 1-5611 (10)(aa)* -- Parent Guaranty dated as of June 14, 1990 from CMS Energy to MCV, each of the Owner Trustees, the Indenture Trustees, the Owner Participants and the Initial Purchasers of Senior Bonds in the MCV Sale Leaseback transaction, and MEC Development (1991 Form 10-K) (10)(r) 1-8157 10.41 -- Contract for Firm Transportation of Natural Gas between Consumers Power Company and Trunkline Gas Company, dated November 1, 1989, and Amendment, dated November 1, 1989 (1989 Form 10-K of PanEnergy Corp.) (10)(s) 1-8157 10.41 -- Contract for Firm Transportation of Natural Gas between Consumers Power Company and Trunkline Gas Company, dated November 1, 1989 (1991 Form 10-K of PanEnergy Corp.) (10)(t) 1-2921 10.03 -- Contract for Firm Transportation of Natural Gas between Consumers Power Company and Trunkline Gas Company, dated September 1, 1993 (1993 Form 10-K) (10)(u) 1-5611 10 -- First Amended and Restated Employment Agreement between Kenneth Whipple and CMS Energy Corporation effective as of September 1, 2003 (8-K dated October 24, 2003) (10)(v) 1-5611 (10)(a) -- Asset Sale Agreement dated as of July 11, 2006 by and among Consumers Energy Company as Seller and Entergy Nuclear Palisades, LLC as Buyer (2nd qtr 2006 Form 10-Q) (10)(w) 1-5611 (10)(b) -- Palisades Nuclear Power Plant Power Purchase Agreement dated as of July 11, 2006 between Entergy Nuclear Palisades, LLC and Consumers Energy Company (2nd qtr 2006 Form 10-Q) (10)(x) 1-9513 99.2 -- Letter of Intent dated January 31, 2007 between CMS Enterprises Company and Lucid Energy LLC (Form 8-K filed February 1, 2007) (10)(y) 1-9513 99.2 -- Agreement of Purchase and Sale by and between CMS Enterprises Company and Abu Dhabi National Energy Company PJSC dated as of February 3, 2007 (Form 8- K filed February 6, 2007)
CO-12
PREVIOUSLY FILED -------------------------- WITH FILE AS EXHIBIT EXHIBITS NUMBER NUMBER DESCRIPTION -------- --------- ---------- ----------- (10)(z) 1-9513 99.2 -- Memorandum of Understanding dated February 13, 2007 between CMS Energy Corporation and Petroleos de Venezuela, S.A. (Form 8-K filed February 14, 2007) (12)(a) -- Statement regarding computation of CMS Energy's Ratio of Earnings to Fixed Charges and Preferred Dividends (12)(b) -- Statement regarding computation of Consumers' Ratio of Earnings to Fixed Charges and Preferred Dividends and Distributions (21) -- Subsidiaries of CMS Energy and Consumers (23)(a) -- Consent of Ernst & Young LLP for CMS Energy (23)(b) -- Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV (23)(c) -- Consent of Ernst & Young for CMS Energy re: Jorf Lasfar (23)(d) -- Consent of Price Waterhouse for CMS Energy re: Jorf Lasfar (23)(e) -- Consent of Ernst & Young LLP for Consumers (23)(f) -- Consent of PricewaterhouseCoopers LLP for Consumers re: MCV (24)(a) -- Power of Attorney for CMS Energy (24)(b) -- Power of Attorney for Consumers (31)(a) -- CMS Energy's certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(b) -- CMS Energy's certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(c) -- Consumers' certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(d) -- Consumers' certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (32)(a) -- CMS Energy's certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (32)(b) -- Consumers' certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (99)(a) -- Financial Statements for Jorf Lasfar for the years ended December 31, 2004, 2005, and 2006
-------------- * Obligations of only CMS Holdings and CMS Midland, second tier subsidiaries of Consumers, and of CMS Energy but not of Consumers. Exhibits listed above that have heretofore been filed with the Securities and Exchange Commission pursuant to various acts administered by the Commission, and which were designated as noted above, are hereby incorporated herein by reference and made a part hereof with the same effect as if filed herewith. CO-13 CMS ENERGY CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CMS ENERGY -- PARENT COMPANY CONDENSED STATEMENTS OF INCOME (LOSS)
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ----- ----- ----- (IN MILLIONS) Dividends from Consolidated Subsidiaries................... $ 147 $ 573 $ 413 Other Operating Deductions................................. (115) (33) (12) ----- ----- ----- Total Operating Income................................... 32 540 401 ----- ----- ----- Other Income (Deductions) Equity in undistributed earnings of subsidiaries......... (55) (514) (124) Interest income (expense)................................ -- (14) (12) Gain on sale of assets................................... -- -- 3 Other.................................................... (6) (11) (1) ----- ----- ----- (61) (539) (134) ----- ----- ----- Fixed Charges Interest on long-term debt............................... 173 184 213 Interest on preferred securities......................... 14 14 14 Intercompany interest expense and other.................. 24 7 30 ----- ----- ----- 211 205 257 ----- ----- ----- Income (Loss) Before Income Taxes.......................... (240) (204) 10 Income Tax Benefit....................................... (161) (121) (110) ----- ----- ----- Income (Loss) From Continuing Operations................... (79) (83) 120 Income (Loss) From Discontinued Operations............... -- (1) 1 ----- ----- ----- Net Income (Loss).......................................... (79) (84) 121 Preferred Dividends........................................ 11 10 11 ----- ----- ----- Net Income (Loss) Available to Common Stockholders......... $ (90) $ (94) $ 110 ===== ===== =====
The accompanying condensed notes are an integral part of these statements. CO-14 CMS ENERGY CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CMS ENERGY -- PARENT COMPANY STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31 2006 2005 2004 ----------------------- ----- ----- ----- (IN MILLIONS) Cash Flows From Operating Activities Net income (loss)........................................ $ (79) $ (84) $ 121 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Equity earnings of subsidiaries..................... (92) (59) (289) Dividends received from subsidiaries................ 147 573 413 Depreciation........................................ 3 2 1 Gain on sale of assets.............................. -- -- (3) Decrease (increase) in accounts receivable.......... (77) -- 9 Increase (decrease) in accounts payable............. 2 (9) (11) Increase in legal settlement liability.............. 200 -- -- Change in other assets and liabilities.............. (13) (10) (69) ----- ----- ----- Net cash provided by operating activities............. 91 413 172 ----- ----- ----- Cash Flows From Investing Activities Investment in subsidiaries............................... (216) (855) (462) Return of investment..................................... -- -- 113 Changes in notes receivable, net......................... (15) 267 21 ----- ----- ----- Net cash used in investing activities................. (231) (588) (328) ----- ----- ----- Cash Flows From Financing Activities Proceeds from bank loans and notes....................... -- 275 287 Proceeds from issuance of common stock................... 23 295 290 Retirement of bank loans and notes....................... (75) (323) (632) Payment of preferred stock dividends..................... (11) (11) (11) Debt issuance costs and financing fees................... (5) (16) -- Changes in notes payable, net............................ 208 (45) 222 ----- ----- ----- Net cash provided by financing activities............. 140 175 156 ----- ----- ----- Net Change in Cash and Temporary Cash Investments.......... $ -- $ -- $ -- Cash and Temporary Cash Investments, Beginning of Period... $ -- $ -- $ -- Cash and Temporary Cash Investments, End of Period......... $ -- $ -- $ -- ===== ===== =====
The accompanying condensed notes are an integral part of these statements. CO-15 CMS ENERGY CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CMS ENERGY -- PARENT COMPANY CONDENSED BALANCE SHEETS
DECEMBER 31 2006 2005 ----------- ------ ------ (IN MILLIONS) ASSETS Property, Plant and Equipment, at cost........................... $ 16 $ 16 Less accumulated depreciation.................................. (9) (6) ------ ------ 7 10 ------ ------ Investment in Subsidiaries....................................... 5,205 5,051 ------ ------ Current Assets Cash and temporary cash investments............................ -- -- Notes and accrued interest receivable.......................... 44 28 Accrued taxes receivable....................................... -- 19 Accounts receivable, including intercompany and related parties..................................................... 90 13 Deferred income taxes.......................................... 102 -- Prepayments and other current assets........................... 2 2 ------ ------ 238 62 ------ ------ Non-current Assets Preferred income taxes......................................... 286 309 Other investment -- SERP....................................... 17 17 Other.......................................................... 29 37 ------ ------ 332 363 ------ ------ TOTAL ASSETS..................................................... $5,782 $5,486 ====== ====== STOCKHOLDERS' INVESTMENT AND LIABILITIES Capitalization Common stockholders' equity.................................... $2,234 $2,322 Nonredeemable preferred stock.................................. 250 250 Intercompany notes payable..................................... 128 187 Long-term debt Senior Notes................................................ 1,833 2,199 Related Party............................................... 178 178 Unamortized Discount........................................ (8) (11) ------ ------ 4,615 5,125 ------ ------ Current Liabilities Current portion of long-term debt.............................. 439 150 Accounts and notes payable, including intercompany and related parties..................................................... 323 54 Accrued interest, including intercompany....................... 60 59 Accrued taxes.................................................. 53 -- Legal settlement liability..................................... 200 -- Other.......................................................... 11 21 ------ ------ 1,086 284 ------ ------ Non-Current Liabilities Postretirement benefits........................................ 24 20 Other.......................................................... 57 57 ------ ------ 81 77 ------ ------ TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES................... $5,782 $5,486 ====== ======
The accompanying condensed notes are an integral part of these statements. CO-16 CMS ENERGY CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CMS ENERGY -- PARENT COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CORPORATE STRUCTURE AND BASIS OF PRESENTATION: CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers Energy and Enterprises. The condensed financial statements of CMS Energy -- Parent Company reflect the investments in wholly owned subsidiaries using the equity method of accounting. USE OF ESTIMATES: CMS Energy is required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates. We record estimated liabilities for contingencies in our condensed financial statements when it is probable that a loss will be incurred in the future as a result of a current event, and when an amount can be reasonably estimated. 2: CONTINGENCIES SECURITIES CLASS ACTION LAWSUITS: On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the "MOU") dated December 28, 2006, subject to court approval, regarding settlement of the two class action lawsuits. The settlement was approved by a special committee of independent directors and by the full board of directors. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. The MOU is expected to lead to a detailed stipulation of settlement that will be presented to the assigned federal judge and the affected class in the first quarter of 2007. Under the terms of the MOU, the litigation will be settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy will make a payment of approximately $123 million plus an amount equivalent to interest on the outstanding unpaid settlement balance beginning on the date of preliminary approval of the court and running until the balance of the settlement funds is paid into a settlement account. Out of the total settlement, CMS Energy's insurers will pay approximately $77 million directly to the settlement account. CMS Energy took an approximately $123 million net pre-tax charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS Energy makes no admission of liability under the Shareholder Action and the ACTS Action. At December 31, 2006, we have recorded the $77 million as an accounts receivable and the $200 million as a legal settlement liability on our CMS Energy -- Parent Company Condensed Balance Sheets. Additional details are included in Note 3, Contingencies to the Annual Report. 3: FINANCINGS Long-term debt, including current maturities was $2,272 million at December 31, 2006 and $2,349 million at December 31, 2005. Long-term debt -- related parties was $178 million at December 31, 2006 and December 31, 2005. At December 31, 2006, the annual maturities for long-term debt and long- term debt -- related parties for the next five years are:
PAYMENTS DUE -------------------------------- 2007 2008 2009 2010 2011 ---- ---- ---- ---- ---- (IN MILLIONS) Long-term debt and long-term debt -- related parties.......................................... $289 $260 $409 $300 $300 ==== ==== ==== ==== ====
Additional details on long-term debt, dividend restrictions and capitalization are included in Note 4, Financings and Capitalization to the Annual Report. 4: RELATED PARTY TRANSACTIONS COMMON STOCK: Consumers Energy held 2.2 million shares of CMS Energy's common stock at December 31, 2006 and 2.3 million shares at December 31, 2005. CO-17 CMS ENERGY CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CMS ENERGY -- PARENT COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED) CASH DIVIDENDS PAID: Our consolidated subsidiaries, Consumers Energy and Enterprises paid the following common stock dividends to CMS Energy for the years ended December 31:
2006 2005 2004 ---- ---- ---- (IN MILLIONS) Dividends: Consumers Energy........................................... $147 $277 $190 Enterprises................................................ -- 296 223 ---- ---- ---- Total........................................................ $147 $573 $413 ==== ==== ====
CO-18 CMS ENERGY CORPORATION SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
CHARGED/ BALANCE AT ACCRUED BALANCE BEGINNING CHARGED TO OTHER AT END DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD ----------- ---------- ---------- -------- ---------- --------- (IN MILLIONS) Accumulated provision for uncollectible accounts: 2006................................. $31 $28 $-- $26 $ 33 2005................................. $38 $23 $-- $30 $ 31 2004................................. $40 $19 $-- $21 $ 38 Deferred tax valuation allowance: 2006................................. $10 $31 $86 $11 $116 2005................................. $42 $ 1 $-- $33 $ 10 2004................................. $42 $ 1 $-- $ 1 $ 42 Allowance for notes receivable, including related parties: 2006................................. $49 $55 $-- $ 4 $100 2005................................. $40 $ 9 $-- $-- $ 49 2004................................. $40 $-- $-- $-- $ 40
CONSUMERS ENERGY COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
CHARGED/ BALANCE AT ACCRUED BALANCE BEGINNING CHARGED TO OTHER AT END DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD ----------- ---------- ---------- -------- ---------- --------- (IN MILLIONS) Accumulated provision for uncollectible accounts: 2006................................. $13 $30 $-- $29 $14 2005................................. $10 $24 $-- $21 $13 2004................................. $ 8 $20 $-- $18 $10 Deferred tax valuation allowance: 2006................................. $-- $16 $-- $ 1 $15 2005................................. $ 9 $ 1 $-- $10 $-- 2004................................. $ 8 $ 1 $-- $-- $ 9
CO-19 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, CMS Energy Corporation has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 23rd day of February 2007. CMS ENERGY Corporation By /s/ DAVID W. JOOS ------------------------------------- David W. Joos President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of CMS Energy Corporation and in the capacities and on the 23rd day of February 2007.
SIGNATURE TITLE --------- ----- (i) Principal executive officer: President and Chief Executive Officer /s/ DAVID W. JOOS ------------------------------ David W. Joos (ii) Principal financial officer: Executive Vice President and /s/ THOMAS J. WEBB Chief Financial Officer ------------------------------ Thomas J. Webb (iii) Controller or principal accounting officer: Vice President, Controller and /s/ GLENN P. BARBA Chief Accounting Officer ------------------------------ Glenn P. Barba (iv) A majority of the Directors including those named above: Director * ------------------------------ Merribel S. Ayres Director * ------------------------------ Jon E. Barfield Director * ------------------------------ Richard M. Gabrys Director * ------------------------------ David W. Joos Director * ------------------------------ Philip R. Lochner, Jr. Director * ------------------------------ Michael T. Monahan Director * ------------------------------ Joseph F. Paquette, Jr.
CO-20
SIGNATURE TITLE --------- ----- Director * ------------------------------ Percy A. Pierre Director * ------------------------------ Kenneth L. Way Director * ------------------------------ Kenneth Whipple Director * ------------------------------ John B. Yasinsky *By /s/ THOMAS J. WEBB ------------------------------ Thomas J. Webb, Attorney-in-Fact
CO-21 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Consumers Energy Company has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 23rd day of February 2007. CONSUMERS ENERGY COMPANY By /s/ DAVID W. JOOS ------------------------------------- David W. Joos Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of Consumers Energy Company and in the capacities and on the 23rd day of February 2007.
SIGNATURE TITLE --------- ----- (i) Principal executive officer: Chief Executive Officer /s/ DAVID W. JOOS ------------------------------ David W. Joos (ii) Principal financial officer: Executive Vice President and /s/ THOMAS J. WEBB Chief Financial Officer ------------------------------ Thomas J. Webb (iii) Controller or principal accounting officer: Vice President, Controller and /s/ GLENN P. BARBA Chief Accounting Officer ------------------------------ Glenn P. Barba (iv) A majority of the Directors including those named above: Director * ------------------------------ Merribel S. Ayres Director * ------------------------------ Jon E. Barfield Director * ------------------------------ Richard M. Gabrys Director * ------------------------------ David W. Joos Director * ------------------------------ Philip R. Lochner, Jr. Director * ------------------------------ Michael T. Monahan Director * ------------------------------ Joseph F. Paquette, Jr.
CO-22
SIGNATURE TITLE --------- ----- Director * ------------------------------ Percy A. Pierre Director * ------------------------------ Kenneth L. Way Director * ------------------------------ Kenneth Whipple Director * ------------------------------ John B. Yasinsky *By /s/ THOMAS J. WEBB ------------------------------ Thomas J. Webb, Attorney-in-Fact
CO-23 CMS ENERGY'S AND CONSUMERS' EXHIBIT INDEX
EXHIBITS DESCRIPTION -------- ----------- (10)(f) -- CMS Energy's Performance Incentive Stock Plan effective February 3, 1988, as amended June 1, 2004 and as further amended effective February 20, 2007. (10)(h) -- Annual Officer Incentive Compensation Plan for CMS Energy Corporation and its Subsidiaries effective January 1, 2006 (12)(a) -- Statement regarding computation of CMS Energy's Ratio of Earnings to Fixed Charges and Preferred Dividends (12)(b) -- Statement regarding computation of Consumers' Ratio of Earnings to Fixed Charges and Preferred Dividends and Distributions (21) -- Subsidiaries of CMS Energy and Consumers (23)(a) -- Consent of Ernst & Young LLP for CMS Energy (23)(b) -- Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV (23)(c) -- Consent of Ernst & Young for CMS Energy re: Jorf Lasfar (23)(d) -- Consent of Price Waterhouse for CMS Energy re: Jorf Lasfar (23)(e) -- Consent of Ernst & Young LLP for Consumers (23)(f) -- Consent of PricewaterhouseCoopers LLP for Consumers re: MCV (24)(a) -- Power of Attorney for CMS Energy (24)(b) -- Power of Attorney for Consumers (31)(a) -- CMS Energy's certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(b) -- CMS Energy's certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(c) -- Consumers' certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(d) -- Consumers' certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (32)(a) -- CMS Energy's certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (32)(b) -- Consumers' certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (99)(a) -- Financial Statements for Jorf Lasfar for the years ended December 31, 2004, 2005, and 2006