10-Q 1 k88652e10vq.txt QUARTERLY REPORT FOR PERIOD ENDED SEPTEMBER 30, 2004 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004 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 Indicate by check mark whether the Registrants (1) have 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 Registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the Registrants are accelerated filers (as defined in Rule 12b-2 of the Exchange Act). CMS ENERGY CORPORATION: Yes [X] No [ ] CONSUMERS ENERGY COMPANY: Yes [ ] No [X] Number of shares outstanding of each of the issuer's classes of common stock at October 31, 2004: CMS ENERGY CORPORATION: CMS Energy Common Stock, $.01 par value 194,725,703 CONSUMERS ENERGY COMPANY, $10 par value, privately held by CMS Energy Corporation 84,108,789 ================================================================================ CMS ENERGY CORPORATION AND CONSUMERS ENERGY COMPANY QUARTERLY REPORTS ON FORM 10-Q TO THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION FOR THE QUARTER ENDED SEPTEMBER 30, 2004 This combined Form 10-Q is separately filed by CMS Energy Corporation and Consumers Energy Company. Information contained herein relating to each individual registrant is filed by such registrant on its own behalf. Accordingly, except for its subsidiaries, Consumers Energy Company makes no representation as to information relating to any other companies affiliated with CMS Energy Corporation. TABLE OF CONTENTS
Page ---- Glossary.................................................................................................. 4 PART I: FINANCIAL INFORMATION CMS Energy Corporation Management's Discussion and Analysis Executive Overview.............................................................................. CMS - 1 Restatement of 2003 Financial Statements........................................................ CMS - 2 Consolidation of Variable Interest Entities..................................................... CMS - 2 Forward-Looking Statements and Risk Factors..................................................... CMS - 2 Results of Operations........................................................................... CMS - 4 Critical Accounting Policies.................................................................... CMS - 13 Capital Resources and Liquidity................................................................. CMS - 25 Outlook......................................................................................... CMS - 28 New Accounting Standards........................................................................ CMS - 40 Consolidated Financial Statements Consolidated Statements of Income (Loss)........................................................ CMS - 44 Consolidated Statements of Cash Flows........................................................... CMS - 46 Consolidated Balance Sheets..................................................................... CMS - 48 Consolidated Statements of Common Stockholders' Equity.......................................... CMS - 50 Condensed Notes to Consolidated Financial Statements: 1. Corporate Structure and Accounting Policies................................................ CMS - 51 2. Discontinued Operations, Other Asset Sales, Impairments, and Restructuring................. CMS - 54 3. Uncertainties.............................................................................. CMS - 59 4. Financings and Capitalization.............................................................. CMS - 85 5. Earnings Per Share......................................................................... CMS - 90 6. Financial and Derivative Instruments....................................................... CMS - 92 7. Retirement Benefits........................................................................ CMS - 98 8. Equity Method Investments.................................................................. CMS - 99 9. Reportable Segments........................................................................ CMS - 100 10. Asset Retirement Obligations............................................................... CMS - 102 11. Implementation of New Accounting Standards................................................. CMS - 104
2 TABLE OF CONTENTS (CONTINUED)
Page ---- Consumers Energy Company Management's Discussion and Analysis Executive Overview.............................................................................. CE - 1 Consolidation of the MCV Partnership and the FLMP............................................... CE - 2 Forward-Looking Statements and Risk Factors..................................................... CE - 2 Results of Operations........................................................................... CE - 4 Critical Accounting Policies.................................................................... CE - 8 Capital Resources and Liquidity................................................................. CE - 17 Outlook......................................................................................... CE - 19 New Accounting Standards........................................................................ CE - 30 Consolidated Financial Statements Consolidated Statements of Income............................................................... CE - 33 Consolidated Statements of Cash Flows........................................................... CE - 34 Consolidated Balance Sheets..................................................................... CE - 36 Consolidated Statements of Common Stockholder's Equity.......................................... CE - 38 Condensed Notes to Consolidated Financial Statements: 1. Corporate Structure and Accounting Policies................................................. CE - 41 2. Uncertainties............................................................................... CE - 44 3. Financings and Capitalization............................................................... CE - 65 4. Financial and Derivative Instruments........................................................ CE - 68 5. Retirement Benefits......................................................................... CE - 72 6. Asset Retirement Obligations................................................................ CE - 73 7. Implementation of New Accounting Standards.................................................. CE - 75 Quantitative and Qualitative Disclosures about Market Risk................................................ CO - 1 Controls and Procedures................................................................................... CO - 1 PART II: OTHER INFORMATION Item 1. Legal Proceedings............................................................................ CO - 1 Item 5. Other Information............................................................................ CO - 6 Item 6. Exhibits and Reports on Form 8-K............................................................. CO - 6 Signatures........................................................................................... CO - 8
3 GLOSSARY Certain terms used in the text and financial statements are defined below 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. AEP............................................... American Electric Power, a non-affiliated company ALJ............................................... Administrative Law Judge Alliance RTO...................................... Alliance Regional Transmission Organization Alstom............................................ Alstom Power Company 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 Articles.......................................... Articles of Incorporation Attorney General.................................. Michigan Attorney General bcf............................................... Billion cubic feet Big Rock.......................................... Big Rock Point nuclear power plant, owned by Consumers Board of Directors................................ Board of Directors of CMS Energy Btu............................................... British thermal unit CEO............................................... Chief Executive Officer CFO............................................... Chief Financial Officer Clean Air Act..................................... Federal Clean Air Act, as amended CMS Electric and Gas.............................. CMS Electric and Gas Company, a subsidiary of Enterprises 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 ERM........................................... CMS Energy Resource Management Company, formerly CMS MST, a subsidiary of Enterprises CMS Field Services................................ CMS Field Services, 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 subsidiary of Enterprises CMS Generation.................................... CMS Generation Co., a subsidiary of Enterprises CMS Holdings...................................... CMS Midland Holdings Company, a subsidiary of Consumers CMS Midland....................................... CMS Midland Inc., a subsidiary of Consumers CMS MST........................................... CMS Marketing, Services and Trading Company, a wholly owned subsidiary of Enterprises, whose name was changed to CMS ERM effective January 2004
4 CMS Oil and Gas................................... CMS Oil and Gas Company, formerly a subsidiary of Enterprises CMS PEPS.......................................... CMS Energy Premium Equity Participating Security Units (CMS Energy Trust III) CMS Pipeline Assets............................... CMS Enterprises pipeline assets in Michigan and Australia CMS Viron......................................... CMS Viron Energy Services, formerly a wholly owned subsidiary of CMS MST. The sale of this subsidiary closed in June 2003. Common Stock...................................... All classes of Common Stock of CMS Energy and each of its subsidiaries, or any of them individually, at the time of an award or grant under the Performance Incentive Stock Plan Consumers......................................... Consumers Energy Company, a subsidiary of CMS Energy Consumers Funding................................. Consumers Funding LLC, a wholly owned special purpose subsidiary of Consumers for the issuance of securitization bonds dated November 8, 2001 Consumers Receivables Funding II.................. Consumers Receivables Funding II LLC, a wholly owned subsidiary of Consumers Court of Appeals.................................. Michigan Court of Appeals CPEE.............................................. Companhia Paulista de Energia Eletrica, a subsidiary of Enterprises Customer Choice Act............................... Customer Choice and Electricity Reliability Act, a Michigan statute enacted in June 2000 that allows all retail customers choice of alternative electric suppliers as of January 1, 2002, provides for full recovery of net stranded costs and implementation costs, establishes a five percent reduction in residential rates, establishes rate freeze and rate cap, and allows for Securitization Detroit Edison.................................... The Detroit Edison Company, a non-affiliated company DIG............................................... Dearborn Industrial Generation, LLC, a wholly owned subsidiary of CMS Generation DOE............................................... U.S. Department of Energy DOJ............................................... U.S. Department of Justice Dow............................................... The Dow Chemical Company, a non-affiliated company EBITDA............................................ Earnings before income taxes, depreciation, and amortization 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 ........................................ Hidroelectrica El Chocon, S.A., a 1,320 MW hydroelectric generating complex in Argentina, in which CMS Energy holds a 17.23 percent ownership interest Enterprises....................................... CMS Enterprises Company, a subsidiary of CMS Energy EPA............................................... U. S. Environmental Protection Agency EPS............................................... Earnings per share ERISA............................................. Employee Retirement Income Security Act Ernst & Young..................................... Ernst & Young LLP
5 Exchange Act...................................... Securities Exchange Act of 1934, as amended FASB.............................................. Financial Accounting Standards Board FASB Staff Position, No. 106-1.................... Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (January 12, 2004) FASB Staff Position, No. 106-2.................... Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (May 19, 2004) FERC.............................................. Federal Energy Regulatory Commission FMB............................................... First Mortgage Bonds FMLP.............................................. First Midland Limited Partnership, a partnership that holds a lessor interest in the MCV facility Ford.............................................. Ford Motor Company FSP............................................... FASB Staff Position GAAP.............................................. Generally Accepted Accounting Principles GasAtacama........................................ An integrated natural gas pipeline and electric generation project located in Argentina and Chile which includes 702 miles of natural gas pipeline and a 720 MW gross capacity power plant GCR............................................... Gas cost recovery GEII.............................................. General Electric International Inc. Goldfields........................................ A pipeline business located in Australia, in which CMS Energy formerly held a 39.7 percent ownership interest Guardian.......................................... Guardian Pipeline, LLC, in which CMS Gas Transmission owned a one-third interest Health Care Plan.................................. The medical, dental, and prescription drug programs offered to eligible employees of Consumers and CMS Energy HL Power.......................................... H.L. Power Company, a California Limited Partnership, owner of the Honey Lake generation project in Wendel, California Integrum.......................................... Integrum Energy Ventures, LLC IPP............................................... Independent Power Production JOATT............................................. Joint Open Access Transmission Tariff Jorf Lasfar....................................... The 1,356 MW coal-fueled power plant in Morocco, jointly owned by CMS Generation and ABB Energy Ventures, Inc. Karn.............................................. D.E Karn/J.C. Weadock Generating Complex, which is owned by Consumers kWh............................................... Kilowatt-hour LIBOR............................................. London Inter-Bank Offered Rate 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 held a 50 percent ownership interest LNG............................................... Liquefied natural gas
6 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............................................... Thousand cubic feet MCV Expansion, LLC................................ An agreement entered into with General Electric Company to expand the MCV Facility MCV Facility...................................... A natural gas-fueled, combined-cycle cogeneration facility operated by the MCV Partnership MCV Partnership................................... Midland Cogeneration Venture Limited Partnership in which Consumers has a 49 percent interest through CMS Midland MD&A.............................................. Management's Discussion and Analysis MDEQ.............................................. Michigan Department of Environmental Quality METC.............................................. Michigan Electric Transmission Company, formerly a subsidiary of Consumers and now an indirect subsidiary of Trans-Elect Michigan Power.................................... CMS Generation Michigan Power, LLC, owner of the Kalamazoo River Generating Station and the Livingston Generating Station MISO.............................................. Midwest Independent System Operator Moody's........................................... Moody's Investors Service, Inc. MPSC.............................................. Michigan Public Service Commission MSBT.............................................. Michigan Single Business Tax MTH............................................... Michigan Transco Holdings, Limited Partnership MW................................................ Megawatts NEIL.............................................. Nuclear Electric Insurance Limited, an industry mutual insurance company owned by member utility companies 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 NERC.............................................. North American Electric Reliability Council NRC............................................... Nuclear Regulatory Commission NYMEX............................................. New York Mercantile Exchange OATT.............................................. Open Access Transmission Tariff OPEB.............................................. Postretirement benefit plans other than pensions for retired employees Palisades......................................... Palisades nuclear power plant, which is owned by Consumers
7 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 Pension Plan...................................... The trusteed, non-contributory, defined benefit pension plan of Panhandle, Consumers and CMS Energy PJM RTO........................................... Pennsylvania-Jersey-Maryland Regional Transmission Organization Powder River...................................... CMS Oil & Gas previously owned a significant interest in coalbed methane fields or projects developed within the Powder River Basin which spans the border between Wyoming and Montana. The Powder River properties have been sold. 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 and Consumers. 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 of 1935 PURPA............................................. Public Utility Regulatory Policies Act of 1978 RCP............................................... Resource Conservation Plan ROA............................................... Retail Open Access RTO............................................... Regional Transmission Organization Rouge............................................. Rouge Steel Industries SCP............................................... Southern Cross Pipeline in Australia, in which CMS Gas Transmission formerly held a 45 percent ownership interest 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
8 SFAS No. 5........................................ SFAS No. 5, "Accounting for Contingencies" SFAS No. 52....................................... SFAS No. 52, "Foreign Currency Translation" 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. 107...................................... SFAS No. 107, "Disclosures about Fair Value of Financial Instruments" SFAS No. 115...................................... SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" SFAS No. 123...................................... SFAS No. 123, "Accounting for Stock-Based Compensation" SFAS No. 128...................................... SFAS No. 128, "Earnings per Share" 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. 148...................................... SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" SFAS No. 149...................................... SFAS No. 149, "Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities" SFAS No. 150...................................... SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" Shuweihat......................................... A power and desalination plant of Emirates CMS Power Company, in which CMS Generation holds a 20 percent interest Southern Union.................................... Southern Union Company, a non-affiliated company Special Committee................................. A special committee of independent directors, established by CMS Energy's Board of Directors, to investigate matters surrounding round-trip trading 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 Taweelah.......................................... Al Taweelah A2, a power and desalination plant of Emirates CMS Power Company, in which CMS Generation holds a 40 percent interest TEPPCO............................................ Texas Eastern Products Pipeline Company, LLC
9 Toledo Power...................................... Toledo Power Company, the 135 MW coal and fuel oil power plant located on Cebu Island, Phillipines, in which CMS Generation held a 47.5 percent interest. Transition Costs.................................. Stranded Costs, as defined, plus the costs incurred in the transition to competition Trunkline......................................... Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle Holdings, LLC Trunkline LNG..................................... Trunkline LNG Company, LLC, formerly a subsidiary of LNG 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 VEBA Trusts....................................... VEBA (voluntary employees' beneficiary association) trust accounts established to specifically set aside employer contributed assets to pay for future expenses of the OPEB plan
10 (This page intentionally left blank) 11 CMS Energy Corporation CMS ENERGY CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS This MD&A is a combined 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 combined entity, except where it is made clear that such term means only CMS Energy. EXECUTIVE OVERVIEW CMS Energy is an integrated energy company with a business strategy focused 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 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, gas transmission, storage, and processing. Our businesses are affected by weather, especially during the traditional heating and cooling seasons, economic conditions, particularly in Michigan, regulation and regulatory issues that primarily affect our gas and electric utility operations, interest rates, our debt credit rating, and energy commodity prices. Our business strategy involves rebuilding our balance sheet and maintaining focus on our core strength: superior utility operation and service. 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, and to improve earnings and cash flow from the businesses we plan to retain. Much of our asset sales program is complete; we are engaged in selling the remaining businesses that are not strategic to us. Over the next few years, we expect this strategy to reduce our parent company debt substantially, improve our debt ratings, grow earnings at a mid-single digit rate, restore a meaningful dividend, and position the company to make new investments consistent with our strengths. In the near term, our new investments will focus on the utility. We face important challenges in the future. We continue to lose industrial and commercial customers to alternative electric suppliers without receiving compensation for Stranded Costs caused by the lost sales. As of October 2004, we have lost 877 MW or 11 percent of our electric load to these alternative electric suppliers. Based on current trends, we predict load loss by year-end to be in the range of 900 MW to 1,000 MW. However, no assurance can be made that the actual load loss will fall within that range. Existing state legislation encourages competition and provides for recovery of Stranded Costs, but the MPSC has not yet authorized Stranded Cost recovery. We continue to seek resolution of this issue through two pending Stranded Cost cases before the MPSC. In July 2004, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act. Further, higher natural gas prices have harmed the economics of the MCV Partnership and we are seeking approval from the MPSC to change the way the facility is used. Our proposal would reduce gas consumption by an estimated 30 to 40 bcf per year while improving the MCV Partnership's financial performance with no change to customer rates. A portion of the benefits from the proposal will support additional renewable resource development in Michigan. Resolving the issue is important for our shareowners and customers. CMS-1 CMS Energy Corporation Our business plan is targeted at predictable earnings growth and debt reduction. We are now over a year into our plan to reduce, by about half, the debt of CMS Energy over a five-year period. In this regard, in August 2004, Consumers completed an $800 million First Mortgage Bond financing at interest rates ranging from 4.4 percent to 5.5 percent and used the proceeds to retire other higher-interest rate long-term debt. Also in August 2004, we made a $150 million investment in Consumers, providing additional liquidity and flexibility for our utility operations. In October 2004, we issued 32.8 million shares of our common stock, which included an option for an additional 4.3 million shares from the original offering. We realized $288 million in net proceeds from this offering and plan to use the cash to make additional capital infusions into Consumers. In fact, on November 1, 2004, we invested $100 million of those proceeds into Consumers. Pending further capital infusions, the proceeds will be used for general corporate purposes, including temporary investments in short-term securities. The result of these efforts, and others, will be a strong, reliable energy company that will be poised to take advantage of opportunities for further growth. RESTATEMENT OF 2003 FINANCIAL STATEMENTS Our financial statements as of and for the three and nine months ended September 30, 2003, as presented in this Form 10-Q, have been restated for the following matters that were disclosed previously in Note 19, Quarterly Financial and Common Stock Information (Unaudited), in our 2003 Form 10-K/A: - International Energy Distribution, which includes SENECA and CPEE, is no longer considered "discontinued operations," due to a change in our expectations as to the timing of the sales, - certain derivative accounting corrections at our equity affiliates, and - the net loss recorded in the second quarter of 2003 relating to the sale of Panhandle, reflected as Discontinued Operations, was understated by approximately $14 million, net of tax. CONSOLIDATION OF VARIABLE INTEREST ENTITIES Under Revised FASB Interpretation No. 46, we are the primary beneficiary of several entities, most notably the MCV Partnership and the FMLP. As a result, we have consolidated the assets, liabilities, and activities of these entities into our financial statements as of and for the three and nine months ended September 30, 2004. These entities are reported as equity method investments in our financial statements as of and for the three and nine months ended September 30, 2003. The consolidation of these entities had minimal impact on our consolidated net income for the three and nine months ended September 30, 2004 versus the same periods ended September 30, 2003. For additional details, see Note 11, Implementation of New Accounting Standards. FORWARD-LOOKING STATEMENTS AND RISK FACTORS This Form 10-Q and other written and oral statements that we make contain forward-looking statements as defined in Rule 3b-6 of the Exchange Act, as amended, Rule 175 of 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: CMS-2 CMS Energy Corporation - capital and financial market conditions, including the current price of CMS Energy Common Stock and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets as well as 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, - 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, - the extent of favorable regulatory treatment and regulatory lag concerning a number of significant questions presently before the MPSC relating to the Customer Choice Act including: - recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers, - recovery of Clean Air Act costs and other environmental and safety-related expenditures, - power supply and natural gas supply costs when energy supply and oil prices are rapidly increasing, - timely recognition in rates of additional equity investments in Consumers, and - adequate and timely recovery of additional electric and gas rate-based expenditures, - the impact of adverse natural gas prices on the MCV Partnership investment, regulatory decisions concerning the MCV Partnership RCP, and regulatory decisions that limit our recovery of capacity and fixed energy payments, - federal regulation of electric sales and transmission of electricity including re-examination by federal regulators of the market-based sales authorizations by which our subsidiaries participate in wholesale power markets without price restrictions, - energy markets, including 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 problems, or other developments, - the GAAP requirement that we utilize mark-to-market accounting on certain of our energy commodity contracts, and possibly other types of contracts in the future, which may have a negative effect on earnings and could add to earnings volatility, - 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, - nuclear power plant performance, decommissioning, policies, procedures, incidents, and CMS-3 CMS Energy Corporation 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, - 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 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 efficient 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, and - other uncertainties that are difficult to predict, and many of which are beyond our control. RESULTS OF OPERATIONS Our business plan focuses on strengthening our balance sheet and improving financial liquidity through debt reduction and aggressive cost management. The sale of non-strategic and under-performing assets has generated cash to reduce debt, reduced business risk, and provided for more predictable future earnings. CMS-4 CMS Energy Corporation CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for per share amounts) ----------------------------------------------------------------------------------- Restated Three months ended September 30 2004 2003 Change ----------------------------------------------------------------------------------- Net Income (Loss) Available to Common Stock $ 56 $ (69) $ 125 Basic Earnings (Loss) Per Share $0.35 $(0.46) $0.81 Diluted Earnings (Loss) Per Share $0.34 $(0.46) $0.80 ----------------------------------------------------------------------------------- Electric utility $ 49 $ 59 $ (10) Gas utility (11) (19) 8 Enterprises 59 (24) 83 Corporate interest and other (49) (87) 38 Discontinued operations 8 2 6 ----------------------------------------------------------------------------------- CMS Energy Net Income (Loss) Available to Common Stock $ 56 $ (69) $ 125 ===================================================================================
For the three months ended September 30, 2004, our net income available to common stock was $56 million, compared to a net loss available to common stock of $69 million for the three months ended September 30, 2003. The $125 million increase primarily reflects: - a $35 million net gain from the 2004 sale of our Parmelia business and our interest in Goldfields, - a $24 million reduction in corporate interest expense, - an $8 million increase in net income at our gas utility primarily due to the 2004 annual unbilled gas revenue analysis increase in gas revenues versus the 2003 analysis reduction in gas revenues, - a $7 million increase in net income at CMS ERM primarily due to the absence of losses associated with wholesale gas and power contracts sold in 2003, - a $6 million reduction in funded benefits expense due to the OPEB plans accounting for the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 and the positive impact of prior year pension plan contributions on pension plan asset returns, - the absence in 2004 of a $46 million net impairment charge related to our international energy distribution business recorded in 2003, and - the absence in 2004 of a $19 million debt retirement charge recorded in 2003. These increases were offset partially by: - a $10 million reduction in net income at our electric utility primarily due to reduced tariff revenues equivalent to Big Rock nuclear decommissioning surcharges, milder weather, and decreased sales margins from deliveries to customers choosing alternative electric suppliers, - a $7 million reduction in earnings from our equity method investments, and - a $3 million declaration and payment of CMS Energy preferred dividends. For further information, see the individual results of operations for each CMS Energy business segment within this MD&A. CMS-5 CMS Energy Corporation
In Millions (except for per share amounts) ----------------------------------------------------------------------------------- Restated Nine months ended September 30 2004 2003 Change ----------------------------------------------------------------------------------- Net Income (Loss) Available to Common Stock $ 65 $ (52) $ 117 Basic Earnings (Loss) Per Share $0.40 $(0.36) $0.76 Diluted Earnings (Loss) Per Share $0.40 $(0.36) $0.76 ------------------------------------------------------------------------------------ Electric utility $ 124 $ 145 $ (21) Gas utility 46 40 6 Enterprises 36 5 31 Corporate interest and other (147) (198) 51 Discontinued operations 6 (20) 26 Accounting changes - (24) 24 ----------------------------------------------------------------------------------- CMS Energy Net Income (Loss) Available to Common Stock $ 65 $ (52) $ 117 ===================================================================================
For the nine months ended September 30, 2004, our net income available to common stock was $65 million, compared to a net loss available to common stock of $52 million for the nine months ended September 30, 2003. The $117 million increase reflects: - a $51 million reduction in corporate interest and other expenses, - a $35 million net gain from the 2004 sale of our Parmelia business and our interest in Goldfields, - a $20 million reduction in funded benefits expense primarily due to the OPEB plans accounting for the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 and the positive impact of prior year pension plan contributions on pension plan asset returns, - a $12 million increase in net income at CMS ERM primarily due to the absence of losses associated with wholesale gas and power contracts sold in 2003, - a $6 million increase in net income at our gas utility resulting from favorable impacts of the December 2003 rate order outpacing reductions in gas deliveries resulting from milder weather, - the absence in 2004 of a $31 million deferred tax asset valuation reserve established in 2003, - the absence in 2004 of $24 million of charges related to changes in accounting recorded in 2003, - the absence in 2004 of $20 million of losses in Discontinued Operations recorded in 2003, and - the absence in 2004 of a $19 million debt retirement charge recorded in 2003. These increases were partially offset by: - a $30 million increase in net asset impairment charges, - a $21 million reduction in net income at our electric utility primarily due to reduced tariff revenues equivalent to Big Rock nuclear decommissioning surcharges, milder weather and decreased sales margins from deliveries to customers choosing alternative electric suppliers, - an $11 million reduction in earnings from our equity method investments, - a $9 million declaration and payment of CMS Energy preferred dividends, and - the absence in 2004 of $30 million of MSBT refunds received in 2003. For further information, see the individual results of operations for each CMS Energy business segment within this MD&A. CMS-6 CMS Energy Corporation ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions ------------------------------------------------------------------------------------ September 30 2004 2003 Change ------------------------------------------------------------------------------------ Three months ended $ 49 $ 59 $ (10) Nine months ended 124 145 (21) ====================================================================================
Three Months Ended Nine Months Ended September 30, September 30, Reasons for the change: 2004 vs. 2003 2004 vs. 2003 -------------------------------------------------------------------------------- Electric deliveries $(20) $(43) Power supply costs and related revenue 2 (3) Other operating expenses, non-commodity revenue and other income 3 29 General taxes 2 (8) Fixed charges (3) (9) Income taxes 6 13 -------------------------------------------------------------------------------- Total change $(10) $(21) ================================================================================
ELECTRIC DELIVERIES: Electric deliveries, including transactions with wholesale marketers, other electric utilities, and customers choosing alternative suppliers decreased 0.02 billion kWh or 0.2 percent, in the three months ended September 30, 2004 versus the same period in 2003. For the nine months ended September 30, 2004, electric deliveries increased 1.0 billion kWh or 3.5 percent versus the same period in 2003. Electric delivery revenues benefited from the recovery of deferred implementation costs. Recovery of these costs began July 1, 2004 and partially offset revenue reductions attributable to milder summer temperatures, decreased revenues attributable to customers choosing alternative electric suppliers, and tariff revenue reductions. The tariff revenue reductions began January 1, 2004, and were equivalent to the Big Rock nuclear decommissioning surcharge in effect when our electric retail rates were frozen from September 2000 through December 31, 2003. The tariff revenue reductions decreased electric delivery revenue by approximately $9 million in the three months ended September 30, 2004, and $27 million in the nine months ended September 30, 2004 versus the same periods in 2003. The tariff revenue reductions are expected to decrease electric delivery revenue by $35 million for the full year of 2004 versus the full year of 2003. On the positive side, the tariff revenue reductions were reclassified for capped customers as power supply revenue and helped reduce the underrecovery of power supply costs for these customers. POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost recovery rate was a fixed amount per kWh, as required under the Customer Choice Act. Therefore, power supply-related revenue in excess of actual power supply costs increased operating income. By contrast, if power supply-related revenue had been less than actual power supply costs, the underrecovery would have decreased operating income. In 2004, our recovery of power supply costs is no longer fixed, but is instead restricted to a pre-defined limit for certain customer classes. The customer classes that have a pre-defined limit, or cap, on the level of power supply costs they can be charged are primarily the residential and small commercial customer classes. In 2004, to the extent our power supply-related revenue exceeds actual power supply costs, this former benefit is reserved for possible future refund. Prior to a refund, a reserve is decreased for CMS-7 CMS Energy Corporation subsequent underrecoveries before possibly decreasing operating income. In the three months ended September 30, 2004, we have been able to reverse revenues previously reserved in the year and defer certain costs to reduce the impact of underrecoveries on operating income. Consequently, in the three months ended September 30, 2004, operating income increased versus the same period in 2003 due to a prior year underrecovery of power supply costs. Operating income decreased for the nine months ended September 30, 2004 versus the same period in 2003 due to prior year power supply cost overrecoveries. OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the three months ended September 30, 2004, other operating expenses increased $8 million, non-commodity revenue decreased $2 million, and other income increased $13 million versus the same period in 2003. The increase in other income relates primarily to the accrual of interest income on capital expenditures in excess of depreciation, as allowed by the Customer Choice Act. Higher operating expenses reflect increased generating plant operating costs and amortization relating to the recovery of deferred implementation costs, which began July 1, 2004. Decreased non-commodity revenues primarily reflect a reduction in rent revenues. In the nine months ended September 30, 2004, other operating expenses increased $2 million, other income increased $33 million, and non-commodity revenue decreased $2 million versus the same period in 2003. The increase in other income relates primarily to the accrual of interest income on capital expenditures in excess of depreciation, as allowed by the Customer Choice Act. A decline in non-commodity revenues reflects reduced rent revenues in the nine months ended September 30, 2004 versus the same period in 2003. GENERAL TAXES: General taxes decreased in the three months ended September 30, 2004 versus the same period in 2003. This decrease reflects less MSBT expense and reduced property tax expense. General taxes increased in the nine months ended September 30, 2004 versus the same period in 2003 primarily due to reductions in the MSBT expense in 2003. The 2003 reduction was primarily due to CMS Energy's receipt of approval to file consolidated tax returns for the years 2000 and 2001. The taxable income for these years was lower than the amount used to make estimated MSBT payments. These returns were filed in the second quarter of 2003. FIXED CHARGES: Fixed charges increased in the three and nine months ended September 30, 2004 versus the same periods in 2003 due to higher average debt levels, partially offset by a reduction in the average rate of interest. In the three months ended September 30, 2004, the average rate of interest dropped 14 basis points and in the nine months ended September 30, 2004, the average rate of interest dropped 45 basis points versus the same periods in 2003. This decrease in the average rates incorporates the impact of an August 2004 refinancing of $800 million. This refinancing both extended the maturity of the debt, and significantly decreased the long-term debt interest rates of the $800 million. INCOME TAXES: In the three and nine months ended September 30, 2004, income taxes decreased versus the same periods in 2003 primarily due to lower earnings by the electric utility, and the OPEB Medicare Part D federal subsidy that is exempt from federal taxation. CMS-8 CMS Energy Corporation GAS UTILITY RESULTS OF OPERATIONS
In Millions --------------------------------------------------------------------------------- September 30 2004 2003 Change --------------------------------------------------------------------------------- Three months ended $(11) $(19) $8 Nine months ended 46 40 6 =================================================================================
Three Months Ended Nine Months Ended September 30, September 30, Reasons for the change: 2004 vs. 2003 2004 vs. 2003 ----------------------------------------------------------------------------------------- Gas deliveries $10 $(11) Gas rate increase 1 12 Gas wholesale and retail services and other gas revenues - 3 Operation and maintenance (1) (3) Depreciation 2 9 General taxes 2 (2) Fixed charges (3) (9) Income taxes (3) 7 ----------------------------------------------------------------------------------------- Total change $ 8 $ 6 =========================================================================================
GAS DELIVERIES: For the three months ended September 30, 2004, the higher priced non-transportation gas deliveries decreased 0.3 bcf or 1.7 percent versus the same period in 2003. The lower priced transportation gas deliveries to end-use customers decreased 0.6 bcf or 5.3 percent. Despite the decrease in gas deliveries, gas delivery revenue increased in the three months ended September 30, 2004 versus the same period in 2003. This increase reflects the effect of the annual unbilled gas volume analysis on accrued gas revenues versus the 2003 results. In 2004, this analysis supported an increase in unbilled gas volumes that resulted in an increase of accrued gas revenues. In 2003, this annual analysis led to a reduction in accrued gas revenues. For the nine months ended September 30, 2004, gas deliveries, including transportation to end-use customers, decreased 17.8 bcf or 7.5 percent versus the same period in 2003 primarily due to milder weather. GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order authorizing a $19 million annual increase to gas tariff rates. As a result of this order, gas revenues increased for the three and nine months ended September 30, 2004 versus the same periods in 2003. GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the nine months ended September 30, 2004, wholesale and retail services and other gas revenues increased primarily due to increased storage revenue versus the same period in 2003. OPERATION AND MAINTENANCE: For the three and nine months ended September 30, 2004, increased expenditures on safety, reliability, and customer service were offset partially by reduced benefit costs compared to the same periods in 2003. CMS-9 CMS Energy Corporation DEPRECIATION: For the three and nine months ended September 30, 2004, depreciation expense decreased versus the same periods in 2003. The decrease in depreciation expense relates to a reduction in depreciation rates authorized by the MPSC's December 2003 interim rate order. GENERAL TAXES: General taxes decreased in the three months ended September 30, 2004 versus the same period in 2003. This decrease reflects less MSBT expense and decreased property tax expense. For the nine months ended September 30, 2004, general tax expense increased $2 million due to higher MSBT expense versus the same period in 2003. The increase in MSBT expense is primarily due to CMS Energy's receipt of approval to file consolidated tax returns for the years 2000 and 2001. The taxable income for these years was lower than the amount used to make estimated MSBT payments. These returns were filed in the second quarter of 2003. FIXED CHARGES: Fixed charges increased in the three and nine months ended September 30, 2004 versus the same periods in 2003 due to higher average debt levels, partially offset by a reduction in the average rate of interest. In the three months ended September 30, 2004, the average rate of interest dropped 14 basis points and in the nine months ended September 30, 2004, the average rate of interest dropped 45 basis points versus the same periods in 2003. This decrease in the average rates incorporates the impact of an August 2004 refinancing of $800 million. This refinancing both extended the maturity of the debt, and significantly decreased the long-term debt interest rates of the $800 million. INCOME TAXES: For the three months ended September 30, 2004, income taxes increased primarily due to the increased earnings of the gas utility versus the same period in 2003. For the nine months ended September 30, 2004, income taxes decreased due to the income tax treatment of items related to plant, property and equipment as required by past MPSC rulings, the decreased earnings of the gas utility, and the OPEB Medicare Part D federal subsidy that is exempt from federal taxation. CMS-10 CMS Energy Corporation ENTERPRISES RESULTS OF OPERATIONS
In Millions --------------------------------------------------------------------------------------------------------------- September 30 2004 2003 Change --------------------------------------------------------------------------------------------------------------- Three months ended $ 59 $ (24) $ 83 Nine months ended 36 5 31 ===============================================================================================================
Three Months Ended Nine Months Ended Reasons for the change: September 30, September 30, 2004 vs. 2003 2004 vs. 2003 --------------------------------------------------------------------------------------------------------------- Results of FASB Interpretation No. 46 Entities $ 1 $(10) Reasons for change excluding FASB Interpretation No. 46: Operating revenues 5 (398) Cost of gas and purchased power 15 451 Earnings from equity method investees (13) (15) Operation and maintenance 5 14 General taxes, depreciation, and other income (10) (18) Gain on sale of assets 44 54 Asset impairment charges 61 (66) Fixed charges (3) 15 Income taxes (22) 4 --------------------------------------------------------------------------------------------------------------- Total change $ 83 $31 ===============================================================================================================
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: Due to the implementation of FASB Interpretation No. 46, certain equity investments, determined to be variable interest entities under this interpretation, which were included in equity earnings during 2003 are included as fully consolidated subsidiaries in the results of operations for 2004. The net increase in earnings, due to the results of these entities, was $1 million for the three months ended September 30, 2004. This increase was primarily from mark-to-market gains related to gas contracts, offset by increased fuel and dispatch costs. The net decrease in earnings, due to the results of these entities, was $10 million for the nine months ended September 30, 2004. This decrease was primarily due to an increase in fuel and dispatch costs. OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For the three months ended September 30, 2004, operating revenues, net of related cost of gas and purchased power, increased versus the same period in 2003 due to higher margins from South American subsidiaries, partially offset by the termination of the Michigan retail power and gas programs at CMS ERM. For the nine months ended September 30, 2004, operating revenues, net of related cost of gas and purchased power, increased versus the same period in 2003 primarily due to the sale of wholesale gas and power contracts at CMS ERM and the termination of Michigan retail power and gas programs, also at CMS ERM. CMS-11 CMS Energy Corporation EARNINGS FROM EQUITY METHOD INVESTEES: Equity earnings decreased for the three months ended September 30, 2004 versus the same period in 2003 due to mark-to-market losses related to interest rate swaps of $15 million. Equity earnings decreased for the nine months ended September 30, 2004 versus the same period in 2003 primarily due to the effects of the Argentine Government natural gas export restrictions in 2004 on the results of GasAtacama, and less favorable fixed charges. OPERATION AND MAINTENANCE: For the three and nine months ended September 30, 2004, operation and maintenance expenses decreased versus the same period in 2003. Lower expenses in 2004 were primarily due to streamlining and business reduction at CMS ERM and CMS Gas Transmission. GENERAL TAXES, DEPRECIATION AND OTHER INCOME: For the three and nine months ended September 30, 2004, the net of general tax expense, depreciation and other income decreased operating income versus the same period in 2003 primarily as a result of foreign exchange losses partially offset by lower depreciation and general taxes due to streamlining and business reduction at CMS ERM. GAIN ON SALE OF ASSETS: For the three months ended September 30, 2004, gains on asset sales increased $44 million versus the same period in 2003. This is primarily due to the $43 million gain on the sale of Goldfields in 2004. For the nine months ended September 30, 2004, gains on asset sales increased $54 million versus the same period in 2003. This is primarily due to the 2004 gain of $43 million on the sale of Goldfields, and the absence in 2004, of the net loss on the sale of CMS ERM Wholesale Gas and Power contracts and a $4 million loss on the sale of our interest in Guardian Pipeline, LLC recorded in 2003. ASSET IMPAIRMENT: For the three months ended September 30, 2004, asset impairment charges decreased versus the same period in 2003, due to the $61 million reduction in the fair value of our investment in CMS Electric and Gas' Venezuelan distribution facility recorded in 2003. For the nine months ended September 30, 2004, asset impairment charges increased versus the same period in 2003, due to the $136 million reduction in the fair value of Loy Yang recorded in 2004. This increase is partially offset by a $70 million reduction in the fair value of our investment in CMS Electric and Gas' Venezuelan distribution facility and an impairment of two generators recorded in 2003. FIXED CHARGES: For the three months ended September 30, 2004, fixed charges increased versus the same period in 2003 due to the payment of preferred dividends to the investor in our Michigan gas assets in 2004 and higher letter of credit fees. For the nine months ended September 30, 2004, fixed charges decreased versus the same period in 2003 due to lower average debt levels and lower average interest rates primarily resulting from the payoff of a short-term revolving credit line held by CMS Enterprises during 2003, partially offset by the payment of preferred dividends to the investor in our Michigan gas assets in 2004 and higher letter of credit fees. INCOME TAXES: For the three months ended September 30, 2004, income taxes increased versus the same period in 2003 primarily due to higher earnings. For the nine months ended September 30, 2004, income taxes decreased versus the same period in 2003 due to the taxes related to the impairment charge for Loy Yang. CMS-12 CMS Energy Corporation CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS
In Millions ----------------------------------------------------------------------------------- September 30 2004 2003 Change ----------------------------------------------------------------------------------- Three months ended $ (49) $ (87) $ 38 Nine months ended (147) (198) 51 ===================================================================================
For the three months ended September 30, 2004, corporate interest expense and other net expenses were $49 million, a decrease of $38 million versus the same period in 2003. The decrease reflects the absence in 2004 of a $19 million charge related to debt retired in 2003 and $22 million of lower interest and other expenses. This decrease was partially offset by the declaration and payment of $3 million of CMS Energy preferred dividends. For the nine months ended September 30, 2004, corporate interest and other net expenses were $147 million, a decrease of $51 million versus the same period in 2003. The decrease reflects the absence of a $24 million valuation allowance for the possible loss of general business credits, a $19 million charge related to debt retired in 2003, and $51 million of lower interest and other expenses. This decrease was offset partially by the absence of $20 million of MSBT refunds received in 2003, a $14 million reduction of interest expense allocated to Discontinued Operations, and the declaration and payment of $9 million of CMS Energy preferred dividends in 2004. DISCONTINUED OPERATIONS: Net income from Discontinued Operations for the three months ended September 30, 2004 was $8 million, an increase of $6 million versus the same period in 2003. For the three months ended September 30, 2004, income was primarily related to the gain on the sale of our Parmelia business, while the income for the three months ended September 30, 2003 reflects post-sale adjustments of previously recorded asset sale transactions. Net income from Discontinued Operations for the nine months ended September 30, 2004 was $6 million, an increase of $26 million versus the same period in 2003. In 2004, income from the sale of Parmelia was partially offset by losses from other Discontinued Operations. In 2003, the loss included $14 million of interest, after-tax, allocated from Corporate and a $12 million after-tax loss related to the sale of Viron. The 2003 losses were partially offset by income from other Discontinued Operations. For additional details, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. ACCOUNTING CHANGES: A $24 million loss for the cumulative effect of changes in accounting principle was recognized in the first quarter of 2003; $23 million was recognized in conjunction with the adoption of EITF Issue No. 02-03; $1 million was recognized in conjunction with the adoption of SFAS No. 143. 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: - use of estimates in accounting for long-lived assets, contingencies, and equity method investments, - accounting for the effects of industry regulation - accounting for financial and derivative instruments, - accounting for international operations and foreign currency, - accounting for pension and postretirement benefits, CMS-13 CMS Energy Corporation - accounting for asset retirement obligations, and - accounting for nuclear decommissioning costs. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies. USE OF ESTIMATES AND ASSUMPTIONS In preparing our financial statements, we use estimates and assumptions that may affect reported amounts and disclosures. Accounting estimates are used 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. There are risks and uncertainties that may cause actual results to differ from estimated results, such as changes in the regulatory environment, competition, foreign exchange, regulatory decisions, and lawsuits. LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. Tests of impairment are performed periodically 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 $15.377 billion at September 30, 2004, 61 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. If an event occurs or circumstances change in a manner that indicates the recoverability of a long-lived asset should be assessed, we evaluate the asset for impairment. An asset held-in-use is evaluated 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. An asset considered held-for-sale is recorded at the lower of its carrying amount or fair value, less cost to sell. We also assess our ability to recover the carrying amounts of our equity method investments. This assessment requires us to determine the fair values of our equity method investments. The determination of fair value is based on 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 also consider the existence of CMS Energy guarantees on obligations of the investee or other commitments to provide further financial support. 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. If fair values were estimated differently, they could have a material impact on our financial statements. CMS-14 CMS Energy Corporation We are still considering the sale of our remaining non-strategic and under-performing assets, including some assets that were not determined to be impaired. Upon the sale of these assets, the proceeds realized may be materially different from the remaining carrying values. We cannot predict when, or make any assurances that these asset sales will occur. Further, we cannot predict the amount of cash or the value of consideration that may be received. 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 the occurrence is probable and, where determinable, an estimate of the liability amount. The recording of estimated liabilities for contingencies is guided by the principles in SFAS No. 5. We consider many factors in making these assessments, including history and the specifics of each matter. The most significant of these contingencies are our electric and gas environmental estimates, which are discussed in the "Outlook" section included in this MD&A, and the potential underrecoveries from our power purchase contract with the MCV Partnership. MCV UNDERRECOVERIES: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990 and to supply electricity and steam to Dow. We hold a 49 percent partnership interest in the MCV Partnership, and a 35 percent lessor interest in the MCV Facility. Under our PPA with the MCV Partnership, we pay a capacity charge based on the availability of the MCV Facility whether or not electricity is actually delivered to us; a variable energy charge for kWh delivered to us; and a fixed energy charge based on availability up to 915 MW and based on delivery for the remaining 325 MW of contract capacity. The cost that we incur under the MCV Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity and fixed energy payments will aggregate $206 million from 2004 through 2007. For capacity and fixed energy payments billed by the MCV Partnership after September 15, 2007, and not recovered from customers, we expect to claim relief under a regulatory out provision under the MCV Partnership PPA. This provision obligates Consumers to pay the MCV Partnership only those capacity and energy charges that the MPSC has authorized for recovery from electric customers. The effect of any such action would be to: - reduce cash flow to the MCV Partnership, which could have an adverse effect on our investment, and - eliminate our underrecoveries for capacity and fixed energy payments. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. As a result of returning to the PSCR process on January 1, 2004, we returned to dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in order to maximize recovery from electric customers of our capacity and fixed energy payments. This fixed load dispatch increases the MCV Facility's output and electricity production costs, such as natural gas. As the spread between the MCV CMS-15 CMS Energy Corporation Facility's variable electricity production costs and its energy payment revenue widens, the MCV Partnership's financial performance and our investment in the MCV Partnership is and will be impacted negatively. In February 2004, we filed the RCP with the MPSC that is intended to help conserve natural gas and thereby improve our investment in the MCV Partnership, without raising the costs paid by our electric customers. The plan's primary objective is to dispatch the MCV Facility on the basis of natural gas market prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit Consumers' ownership interest in the MCV Partnership. In August 2004, several qualifying facilities sought and obtained a stay of the RCP proceeding from the Ingham County Circuit Court after their previous attempt to intervene in the proceeding was denied by the MPSC. In an attempt to resolve this intervention issue as quickly as possible, the MPSC issued an order permitting the qualifying facilities to participate as intervenors. As a result, the Ingham County Circuit Court stay was lifted and hearings were completed in October 2004. The MPSC has decided to dispense with a Proposal for Decision from the presiding ALJ and will issue a decision directly. We cannot predict if or when the MPSC will approve the RCP. The two most significant variables in the analysis of the MCV Partnership's future financial performance are the forward price of natural gas for the next 20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of capacity and fixed energy payments. Historically, natural gas prices have been volatile. Presently, there is no consensus in the marketplace on the price or range of future prices of natural gas. Even with an approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment of our investment in the MCV Partnership. We presently cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our investment in the MCV Partnership. For additional details on the MCV Partnership, see Note 3, Uncertainties, "Other Consumers' Electric Utility Uncertainties - The Midland Cogeneration Venture." 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, items that a non-regulated entity normally would expense, we may record as regulatory assets if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, items that non-regulated entities may normally recognize as revenues, we may record as regulatory liabilities if the actions of the regulator indicate they will require such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. As of September 30, 2004, we had $1.158 billion recorded as regulatory assets and $1.512 billion recorded as regulatory liabilities. For additional details on industry regulation, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." CMS-16 CMS Energy Corporation ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND MARKET RISK INFORMATION FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities using SFAS No. 115. Debt and equity securities can be classified into one of three categories: held-to-maturity, trading, or available-for-sale. Our debt securities are classified as held-to-maturity securities and are reported at cost. Our investments in equity securities are classified as available-for-sale securities and are reported at fair value determined from quoted market prices. Any unrealized gains or losses resulting from changes in fair value are reported in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses resulting from changes in the fair value of our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as an asset or a liability, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in the fair value of a derivative (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income depending on whether the derivative qualifies for special hedge accounting treatment. The types of contracts we typically classify as derivative instruments are interest rate swaps, foreign currency exchange contracts, electric call options, gas fuel futures and swaps, gas fuel options, gas fuel contracts containing volume optionality, fixed priced weather-based gas supply call options, fixed price gas supply call and put options, and gas and electric forward contracts used for trading purposes. We generally do not account for electric capacity and energy contracts, gas supply contracts, coal and nuclear fuel supply contracts, or purchase orders for numerous supply items as derivatives. The majority of our contracts are not subject to derivative accounting because they qualify for the normal purchases and sales exception of SFAS No. 133, or are not derivatives because there is not an active market for the commodity. Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market, as defined by SFAS No. 133, for the coal that we purchase. If active markets develop in the future, we may be required to account for these contracts as derivatives. The mark-to-market impact on earnings related to these contracts could be material to our financial statements. The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which will include day-ahead and real-time energy market information for the MISO's participants. We are presently evaluating what impacts, if any, this market development will have on the determination of whether an active energy market exists in the state of Michigan. For additional information, see Electric Utility Business Uncertainties, "Transmission Market Developments" within this MD&A. The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that its long-term natural gas contracts, which do not contain volume optionality, qualify under SFAS No. 133 for the normal purchases and normal sales exception. Therefore, these contracts are currently not recognized at fair value on the balance sheet. Should significant changes in the level of the MCV Facility operational dispatch or purchases of long-term gas occur, the MCV Partnership would be required to re-evaluate its accounting treatment for these long- CMS-17 CMS Energy Corporation term gas contracts. This re-evaluation may result in recording mark-to-market activity on some contracts, which could add to earnings volatility. To determine the fair value of contracts that are accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward prices, strike prices, volatilities, interest rates, and maturity dates. Changes in forward prices or volatilities could change significantly the calculated fair value of certain contracts. At September 30, 2004, we assumed a market-based interest rate of 1 percent and monthly volatility rates ranging between 43 percent and 57 percent to calculate the fair value of our gas options. Also, at September 30, 2004, we assumed a market-based interest rate of 1 percent and daily volatility rates ranging between 56 percent and 108 percent to calculate the fair value of our electric options. At September 30, 2004, we assumed market-based interest rates ranging between 1.84 percent and 3.90 percent (depending on the term of the contract) and monthly volatility rates ranging between 34 percent and 63 percent to calculate the fair value of the gas fuel derivative contracts held by the MCV Partnership. TRADING ACTIVITIES: CMS ERM enters into and owns energy contracts that are related to activities considered an integral part of CMS Energy's ongoing operations. We use various financial instruments, including swaps, options, futures, and forward contracts to manage commodity risks associated with generation assets owned by CMS Energy or its subsidiaries and to fulfill our contractual obligations. These contracts are classified as trading activities in accordance with EITF Issue No. 02-03 and are accounted for using the criteria defined in SFAS No. 133. Energy trading contracts that meet the definition of a derivative are recorded as assets or liabilities in the financial statements at the fair value of the contracts. Gains or losses arising from changes in fair value of these contracts are recognized into earnings in the period in which the changes occur. Energy trading contracts that do not meet the definition of a derivative are accounted for as executory contracts (i.e., on an accrual basis). The market prices we use to value our energy trading contracts reflect our consideration of, among other things, closing exchange and over-the-counter quotations. In certain contracts, long-term commitments may extend beyond the period in which market quotations for such contracts are available. Mathematical models are developed to determine various inputs into the fair value calculation including price and other variables that may be required to calculate fair value. Realized cash returns on these commitments may vary, either positively or negatively, from the results estimated through application of the mathematical model. Market prices are adjusted to reflect the impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. In connection with the market valuation of our energy trading contracts, we maintain reserves for credit risks based on the financial condition of counterparties. We also maintain credit policies that management believes will minimize its overall credit risk with regard to our counterparties. Determination of our counterparties' credit quality is based upon a number of factors, including credit ratings, disclosed financial condition, and collateral requirements. Where contractual terms permit, we employ standard agreements that allow for netting of positive and negative exposures associated with a single counterparty. Based on these policies, our current exposures, and our credit reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance. CMS-18 CMS Energy Corporation The following tables provide a summary of the fair value of our energy trading contracts as of September 30, 2004:
In Millions -------------------------------------------------------------------------------------------------- Fair value of contracts outstanding as of December 31, 2003 $ 15 Fair value of new contracts when entered into during the period (a) (3) Changes in fair value attributable to changes in valuation techniques and assumptions - Contracts realized or otherwise settled during the period (17) Other changes in fair value (b) 15 ------------------------------------------------------------------------------------------------- Fair value of contracts outstanding as of September 30, 2004 $ 10 =================================================================================================
(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) Reflects changes in price and net increase/(decrease) of forward positions as well as changes to mark-to-market and credit reserves.
Fair Value of Contracts at September 30, 2004 In Millions ----------------------------------------------------------------------------------------------- Total Maturity (in years) Source of Fair Value Fair Value Less than 1 1 to 3 4 to 5 Greater than 5 ------------------------------------------------------------------- --------------------------- Prices actively quoted $(36) $ (4) $(15) $(17) $ - Prices based on models and other valuation methods 46 12 21 13 - ----------------------------------------------------------------------------------------------- Total $ 10 $ 8 $ 6 $ (4) $ - ===============================================================================================
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 manage these risks 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. We may use various contracts to manage these risks, including swaps, options, futures, and forward contracts. Contracts used to manage market risks may be considered derivative instruments that are subject to derivative and hedge accounting pursuant to SFAS No. 133. We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. Risk management contracts are classified as either trading or other than trading. These contracts contain credit risk if the counterparties, including financial institutions and energy marketers, fail to perform under the agreements. We minimize such risk by performing financial credit reviews using, among other things, publicly available credit ratings of such counterparties. We perform sensitivity analyses to assess the potential loss in fair value, cash flows, or future earnings based upon a hypothetical 10 percent adverse change in market rates or prices. We do not believe that sensitivity analyses alone provide an accurate or reliable method for monitoring and controlling risks. Therefore, we use our experience and judgment to revise strategies and modify assessments. Changes in excess of the amounts determined in sensitivity analyses could occur if market rates or prices exceed the 10 percent shift used for the analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity Price Risk," "Trading Activity Commodity Price Risk," "Currency Exchange Risk," and "Investment Securities Price Risk" within this section. CMS-19 CMS Energy Corporation 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 a 10 percent adverse change in market interest rates):
In Millions --------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 --------------------------------------------------------------------------------------------------------- Variable-rate financing - before tax annual earnings exposure $ 1 $ 1 Fixed-rate financing - potential loss in fair value (a) 242 242 =========================================================================================================
(a) Fair value exposure would only be realized if we repurchased all of our fixed-rate financing. Certain equity method investees have issued interest rate swaps. These instruments are not required to be included in the sensitivity analysis, but can have an impact on financial results. Commodity Price Risk: For purposes other than trading, we enter into electric call options, fixed-priced weather-based gas supply call options, and fixed-priced gas supply call and put options. Electric call options are purchased to protect against the risk of fluctuations in the market price of electricity, and to ensure a reliable source of capacity to meet our customers' electric needs. Purchased electric call options give us the right, but not the obligation, to purchase electricity at predetermined fixed prices. Our gas supply call and put options are used to purchase reasonably priced gas supply. Purchases of gas supply call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Gas supply put options sold give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices. At September 30, 2004, we held fixed-priced weather-based gas supply call options and fixed-price gas supply put options. The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. Some of these contracts contain volume optionality and, therefore, are treated as derivative instruments. Also, the MCV Partnership enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements. At September 30, 2004, the MCV Partnership held gas fuel contracts with volume optionality, as well as gas fuel futures and swaps. Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions --------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 --------------------------------------------------------------------------------------------------- Potential reduction in fair value: Gas supply option contracts $ 3 $1 Derivative contracts associated with Consumers' investment in the MCV Partnership: Gas fuel contracts 22 N/A Gas fuel futures and swaps 48 N/A ===================================================================================================
CMS-20 CMS Energy Corporation We did not perform a sensitivity analysis for the derivative contracts held by the MCV Partnership as of December 31, 2003, because the MCV Partnership was not consolidated into our financial statements until March 31, 2004, as discussed in Note 11, Implementation of New Accounting Standards. Trading Activity Commodity Price Risk: We are exposed to market fluctuations in the price of energy commodities. We employ established policies and procedures to manage these risks and may use various commodity derivatives, including futures, options, swaps, and forward contracts. The prices of these energy commodities can fluctuate because of, among other things, changes in the supply of and demand for the commodities. Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions --------------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 --------------------------------------------------------------------------------------------------------------- Potential reduction in fair value: Gas-related swaps, forward contracts, and futures $ 3 $ 3 Electricity-related forward contracts 1 2 Electricity-related call option contracts 1 1 ===============================================================================================================
Currency Exchange Risk: We are exposed to currency exchange risk arising from investments in foreign operations as well as various international projects in which we have an equity interest and which have debt denominated in U.S. dollars. We may use forward exchange contracts and other risk mitigating instruments to hedge currency exchange rates. The impact of hedges on our investments in foreign operations is reflected in accumulated other comprehensive income as a component of the foreign currency translation adjustment on the 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 investments on which the hedges were taken. At September 30, 2004, we had no foreign exchange hedging contracts outstanding. As of September 30, 2004, the total foreign currency translation adjustment was a net loss of $325 million, which included a net hedging loss of $27 million, net of tax, related to settled contracts. Investment Securities Price Risk: We are exposed to price risk associated with investments in equity securities. As discussed in "Financial Instruments" within this section, our investments in equity securities are classified as available-for-sale securities. They are reported at fair value, with any unrealized gains or losses resulting from changes in fair value reported in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses resulting from changes in the fair value of our nuclear decommissioning investments are reflected as regulatory liabilities in our Consolidated Balance Sheets. Our debt securities are classified as held-to-maturity securities and have original maturity dates of approximately one year or less. Because of the short maturity of these instruments, their carrying amounts approximate their fair values. Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions --------------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 --------------------------------------------------------------------------------------------------------------- Potential reduction in fair value: Nuclear decommissioning investments $ 54 $ 57 Other available-for-sale investments 6 7 ===============================================================================================================
CMS-21 CMS Energy Corporation For additional details on market risk and derivative activities, see Note 6, Financial and Derivative Instruments. INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY We have investments in energy-related projects in selected markets around the world. As a result of a change in business strategy, we have been selling certain foreign investments. For additional details on the divestiture of foreign investments, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. BALANCE SHEET: Our subsidiaries and affiliates whose functional currency is other than 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. Gains or losses that result from this translation and gains or losses on long-term intercompany foreign currency transactions are reflected as a component of stockholders' equity in our Consolidated Balance Sheets as "Foreign Currency Translation." As of September 30, 2004, cumulative foreign currency translation decreased stockholders' equity by $325 million. We translate the revenue and expense accounts of these subsidiaries and affiliates into U.S. dollars at the average exchange rate during the period. Australia: The Foreign Currency Translation component of stockholders' equity at December 31, 2003 included an approximate $110 million unrealized net foreign currency translation loss related to our investment in Loy Yang and an approximate $6 million unrealized net foreign currency translation gain related to our investments in SCP and Parmelia. In March 2004, we recognized the Loy Yang foreign currency translation loss in earnings as an impairment of approximately $81 million, net of tax, recorded as a result of the sale of Loy Yang that was completed in April 2004. In August 2004, we sold our investments in SCP and Parmelia and recognized the $6 million foreign currency translation gain. Argentina: At September 30, 2004, the net foreign currency loss due to the unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency Translation component of stockholders' equity using an exchange rate of 3.02 pesos per U.S. dollar was $264 million. This amount also reflects the effect of recording, at December 31, 2002, U.S. income taxes on temporary differences between the book and tax bases of foreign investments, including the foreign currency translation associated with our Argentine investments. INCOME STATEMENT: We use the U.S. dollar as the functional currency of subsidiaries operating in highly inflationary economies and of subsidiaries that meet the U.S. dollar functional currency criteria in SFAS No. 52. Gains and losses that arise from transactions denominated in a currency other than the U.S. dollar, except those that are hedged, are included in determining net income. HEDGING STRATEGY: We may use forward exchange and option contracts to hedge certain receivables, payables, long-term debt, and equity value relating to foreign investments. The purpose of our foreign currency hedging activities is to protect the company from the risk associated with adverse changes in currency exchange rates that could affect cash flow materially. These contracts would not subject us to risk from exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on assets and liabilities being hedged. ACCOUNTING FOR PENSION AND OPEB Pension: We have established external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. We have implemented a cash balance plan for CMS-22 CMS Energy Corporation certain employees hired after June 30, 2003. We use SFAS No. 87 to account for pension costs. 401(k): In our efforts to reduce costs, the employer's match for the 401(k) plan was suspended effective September 1, 2002. It is scheduled to resume on January 1, 2005. OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. We use SFAS No. 106 to account for other postretirement benefit costs. Liabilities for both pension and OPEB are recorded on the balance sheet at the present value of their future obligations, net of any plan assets. The calculation of the liabilities and associated expenses requires the expertise of actuaries. Many assumptions are made 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. Any change in these assumptions can change significantly the liability and associated expenses recognized in any given year. The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years: In Millions
Expected Costs Pension Cost OPEB Cost Contributions --------------------------------------------------------------------------------- 2004 $21 $30 $ 63 2005 52 38 80 2006 73 34 114 =================================================================================
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. As of September 30, 2004, we have a prepaid pension asset of $392 million, $20 million of which is in Prepayments and other current assets on our Consolidated Balance Sheets. Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated pension cost for 2004 by $2 million. Lowering the discount rate by 0.25 percent (from 6.25 percent to 6.00 percent) would increase estimated pension cost for 2004 by $4 million. The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated, retroactively, the effects of the subsidy into our financial statements as of June 30, 2004 in accordance with FASB Staff Position No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $158 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months CMS-23 CMS Energy Corporation ended September 30, 2004, $18 million for the nine months ended September 30, 2004, and an expected total reduction of $24 million for 2004. For additional details on postretirement benefits, see Note 7, Retirement Benefits and Note 11, Implementation of New Accounting Standards. ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS SFAS No. 143 became effective January 2003. It 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 for regulated entities 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, 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. 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 are based on decommissioning studies, which largely utilize third-party cost estimates. For additional details on ARO, see Note 10, Asset Retirement Obligations. ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS The MPSC and the FERC regulate the recovery of costs to decommission our Big Rock and Palisades nuclear plants. We have established 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. 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 have helped us develop decommissioning cost estimates. Various inflation rates for labor, non-labor, and contaminated equipment disposal costs are used 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 fuel from the sites, as required by the Nuclear Waste Policy Act of 1982. CMS-24 CMS Energy Corporation The decommissioning trust funds include equities and fixed income investments. Equities will be converted to fixed income investments during decommissioning, and fixed income investments are converted to cash as needed. In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. The funds provided by the trusts, additional customer surcharges, and potential funds from the DOE litigation are all required to cover fully the decommissioning costs. 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 fully fund the decommissioning of Big Rock or Palisades. 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. We will also seek additional relief from the MPSC. For additional details on nuclear decommissioning, see Note 3, Uncertainties, "Other Consumers' Electric Utility Uncertainties - Nuclear Plant Decommissioning" and "Nuclear Matters." CAPITAL RESOURCES AND LIQUIDITY Our liquidity and capital requirements are a function of our results of operations, capital expenditures, contractual obligations, debt maturities, 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. The market price for natural gas has increased. Although our natural gas purchases are recoverable from our customers, the amount paid for natural gas stored as inventory could require additional liquidity due to the timing of the cost recoveries. In addition, a few of our commodity suppliers have requested advance payment or other forms of assurances, including margin calls, in connection with maintenance of ongoing deliveries of gas and electricity. Our current financial plan includes controlling our operating expenses and capital expenditures, evaluating market conditions for financing opportunities, and selling assets that are not consistent with our strategy. We believe our current level of cash and borrowing capacity, along with anticipated cash flows from operating and investing activities, will be sufficient to meet our liquidity needs through 2005. We have not made a specific determination concerning the reinstatement of common stock dividends. The Board of Directors may reconsider or revise its dividend policy based upon certain conditions, including our results of operations, financial condition, and capital requirements, as well as other relevant factors. In October 2004, we issued 32.8 million shares of our common stock. We realized $288 million in net proceeds from this offering. We will use the net proceeds to make capital infusions into Consumers. Pending such capital infusions, the proceeds will be used for general corporate purposes, including temporary investments in short-term securities. CASH POSITION, INVESTING, AND FINANCING Our operating, investing, and financing activities meet consolidated cash needs. At September 30, 2004, $643 million consolidated cash was on hand, which includes $83 million of restricted cash. For additional details on cash equivalents and restricted cash, see Note 1, Corporate Structure and Accounting Policies. Our primary ongoing source of cash is dividends and other distributions from our subsidiaries, including CMS-25 CMS Energy Corporation proceeds from asset sales. For the first nine months of 2004, Consumers paid $187 million in common stock dividends and Enterprises paid $157 million in common stock dividends and other distributions to CMS Energy. SUMMARY OF CASH FLOWS:
In Millions -------------------------------------------------------------------------------- Nine months ended September 30 2004 2003 -------------------------------------------------------------------------------- Net cash provided by (used in): Operating activities $ 194 $ - Investing activities (132) 332 Financing activities (208) (16) Effect of exchange rates on cash - 2 -------------------------------------------------------------------------------- Net increase (decrease) in cash and cash equivalents $(146) $318 ================================================================================
OPERATING ACTIVITIES: For the nine months ended September 30, 2004, net cash provided by operating activities increased $194 million versus the same period in 2003. The absence, in 2004, of $210 million in pension contributions made in 2003, an increase in accounts payable of $198 million, and a $124 million increase in accrued expenses represent the majority of the increase. The accounts payable increase is largely due to the purchase of natural gas at higher prices, fewer suppliers requiring advanced payments for gas purchases, and the sale of CMS ERM wholesale gas and power books in 2003. Increases in accrued expenses are primarily due to a smaller decrease in accrued taxes in 2004 versus 2003. Collectively, these increases more than offset the $311 million increase in accounts receivable and accrued revenue primarily due to lower sales of accounts receivable resulting from our improved liquidity. INVESTING ACTIVITIES: For the nine months ended September 30, 2004, net cash from investing activities decreased $464 million versus the same period in 2003. This change was primarily due to a decrease in asset sale proceeds of $633 million and an increase in investments in unconsolidated subsidiaries of $70 million due to an infusion to Shuweihat. This was partially offset by a decrease in the amount of cash restricted of $285 million. In 2004, $118 million in restricted cash was no longer required to be held as collateral for letters of credit. For additional details on restricted cash, see Note 1, Corporate Structure and Accounting Policies, "Cash Equivalents and Restricted Cash." FINANCING ACTIVITIES: For the nine months ended September 30, 2004, net cash from financing activities decreased $192 million versus the same period in 2003 primarily due to a decrease of $143 million in net proceeds from borrowings. For additional details on long-term debt activity, see Note 4, Financings and Capitalization. OBLIGATIONS AND COMMITMENTS REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers issues short- and long-term securities under the FERC's authorization. For additional details of Consumers' existing authorization, see Note 4, Financings and Capitalization. LONG-TERM DEBT: The components of long-term debt are presented in Note 4, Financings and Capitalization. CMS-26 CMS Energy Corporation We will extinguish our $180 million, 7 percent extendible tenor rate adjusted securities that were scheduled to mature in January 2005. Upon extinguishment, we will record a charge of approximately $15 million, after-tax, for costs associated with extinguishing this debt. SHORT-TERM FINANCINGS: At September 30, 2004, CMS Energy had $208 million available, Consumers had $475 million available, and the MCV Partnership had $50 million available in short-term credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. Additional details on short-term financings are presented in Note 4, Financings and Capitalization. OFF-BALANCE SHEET ARRANGEMENTS: 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 $1.344 billion at September 30, 2004. The timing of the payments of non-recourse debt only affects the cash flow and liquidity of the partnerships and joint ventures. Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we may sell up to $325 million of certain accounts receivable. For additional details, see Note 4, Financings and Capitalization. CONTINGENT COMMITMENTS: Our contingent commitments include guarantees, indemnities, and letters of credit. Guarantees represent our guarantees of performance, commitments, and liabilities of our consolidated and unconsolidated subsidiaries, partnerships, and joint ventures. Indemnities are agreements to reimburse other companies, such as an insurance company, if those companies have to complete our contractual performance in a third-party contract. 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 and approve these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. Our off-balance sheet commitments at September 30, 2004, expire as follows:
Commercial Commitments In Millions -------------------------------------------------------------------------------------- Commitment Expiration -------------------------------------------------------------------------------------- 2009 and Total 2004 2005 2006 2007 2008 Beyond -------------------------------------------------------------------------------------- Off-balance sheet: Guarantees $ 197 $ 6 $ 36 $ 5 $ - $ - $ 150 Surety bonds and other indemnifications (a) 24 - - - - - 24 Letters of Credit 163 13 115 5 5 5 20 -------------------------------------------------------------------------------------- Total $ 384 $ 19 $ 151 $ 10 $ 5 $ 5 $ 194 ======================================================================================
(a) The surety bonds are continuous in nature. The need for the bonds is determined on an annual basis. DIVIDEND RESTRICTIONS: Our amended and restated $300 million credit facility restricts payments of dividends on our common stock during a 12-month period to $75 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility. Under the provisions of its articles of incorporation, at September 30, 2004, Consumers had $348 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. In CMS-27 CMS Energy Corporation October 2004, the MPSC rescinded its December 2003 interim order, which included a $190 million annual dividend cap imposed on Consumers. For the nine months ended September 30, 2004, we received $187 million of common stock dividends from Consumers. OUTLOOK CORPORATE OUTLOOK During 2004, we have continued to implement a business strategy that involves rebuilding our balance sheet, divesting under-performing or other non-strategic assets, and providing superior utility operations and service. This strategy is designed to generate cash to pay down debt and provide for more predictable future operating revenues and earnings. 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, and to improve earnings and cash flow from businesses we plan to retain. Much of our asset sales program is complete; we are engaged in selling the remaining businesses that are not strategic to us. As this continues, the percentage of our future earnings relating to our larger equity method investments, including Jorf Lasfar, may increase and our total future earnings may depend more significantly upon the performance of those investments. For additional details, see Note 8, Equity Method Investments. Over the next few years, we expect our business strategy to reduce parent company debt substantially, improve our debt ratings, grow earnings at a mid-single digit rate, restore a dividend, and position the company to make new investments consistent with our strengths. In the near term, our new investments will focus on the utility. ELECTRIC UTILITY BUSINESS OUTLOOK GROWTH: Over the next five years, we expect electric deliveries to grow at an average rate of approximately two percent per year, based primarily on a steadily growing customer base and economy. 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 fluctuations in weather conditions and changes in economic conditions, including utilization and expansion of manufacturing facilities. We experienced less growth than expected in 2003 as a result of cooler than normal summer weather and a decline in manufacturing activity in Michigan. In 2004, we have again experienced cooler than normal summer weather. As a result, electric deliveries growth for 2004 is expected to be less than one percent. ELECTRIC UTILITY BUSINESS UNCERTAINTIES Several electric business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric operations. Such trends and uncertainties include: CMS-28 CMS Energy Corporation Environmental - increasing capital expenditures and operating expenses for Clean Air Act compliance, and - potential environmental liabilities arising from various environmental laws and regulations, including potential liability or expenses relating to the Michigan Natural Resources and Environmental Protection Acts and Superfund. Restructuring - response of the MPSC and Michigan legislature to electric industry restructuring issues, - ability to meet peak electric demand requirements at a reasonable cost, without market disruption, - ability to recover any of our net Stranded Costs under the regulatory policies set by the MPSC, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer instead of an electric transmission owner and the impact of the evolving RTO infrastructure. Regulatory - effects of recommendations as a result of the August 14, 2003 blackout, including increased regulatory requirements and new legislation, - regulatory decisions concerning the RCP, - effects of the FERC market power test requirements for electric market-based rate authority, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, and - recovery of nuclear decommissioning costs. For additional details, see "Accounting for Nuclear Decommissioning Costs" within this MD&A. Other - effects of commodity fuel prices such as natural gas, oil, and coal, - pending litigation filed by PURPA qualifying facilities, and - other pending litigation. For additional details about these trends or uncertainties, see Note 3, Uncertainties. 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. Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for us. The Title I provisions of the Clean Air Act require significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $802 million. The key assumptions included 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 - allowance for funds used during construction (AFUDC) rate. Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.06 percent. As of September 30, 2004, we have incurred $500 million in capital expenditures to CMS-29 CMS Energy Corporation comply with these regulations and anticipate that the remaining $302 million of capital expenditures will be made between 2004 and 2011. These expenditures include installing catalytic reduction technology at some of our coal-fired electric plants. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions allowances for years 2004 through 2009. The cost of the allowances is estimated to average $7 million per year for 2004-2006; the cost will decrease after year 2006 with the installation of plant control technology. The cost of the allowances is accounted for as inventory. The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits 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 plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question. The EPA has proposed a Clean Air Interstate Rule that would require additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. If implemented, this rule would potentially require expenditures equivalent to those efforts in progress to reduce nitrogen oxide emissions as required under the Title I provisions of the Clean Air Act. The rule proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent and nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two alternative sets of rules to reduce emissions of mercury and nickel from coal-fired and oil-fired electric plants. Until the proposed environmental rules are finalized, an accurate cost of compliance cannot be determined. Our switch to western coal as fuel has resulted in reduced plant emissions, lower operating costs, and flexibility in meeting future regulatory compliance requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide allowances optimizes our overall cost of regulatory compliance by delaying capital expenditures and minimizing regulatory uncertainty. Western coal has reduced our overall cost of fuel and reduced the impact on us from the recent increases in eastern coal prices. Several bills have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that greenhouse gas emission reduction rules come into effect, such mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sectors. We cannot estimate the potential effect of United States federal or state level greenhouse gas policy on future consolidated results of operations, cash flows, or financial position due to the speculative nature of the policy. We stay abreast of and engage in the greenhouse gas policy developments and will continue to assess and respond to their potential implications on our business operations. In March 2004, the EPA changed the rules that govern generating plant cooling water intake systems. The new rules require significant reduction in fish killed by operating equipment. Some of our facilities will be required to comply by 2006. We are studying the rules to determine the most cost-effective solutions for compliance. For additional details on electric environmental matters, see Note 3, Uncertainties, "Consumers' Electric Utility Contingencies - Electric Environmental Matters." COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act and other developments CMS-30 CMS Energy Corporation will continue to result in increased competition in the electric business. Generally, increased competition reduces profitability and threatens market share for generation services. As of January 1, 2002, the Customer Choice Act allowed all of our electric customers to buy electric generation service from us or from an alternative electric supplier. As a result, alternative electric suppliers for generation services have entered our market. As of October 2004, alternative electric suppliers are providing 877 MW of generation supply to ROA customers. This amount represents 11 percent of our distribution load and an increase of 45 percent compared to October 2003. Based on current trends, we predict load loss by year-end to be in the range of 900 MW to 1,000 MW. However, no assurance can be made that the actual load loss will fall within that range. In July 2004, as a result of legislative hearings, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act. The proposals include: - requiring that rates be based on cost of service, - establishing a defined Stranded Cost calculation method, - allowing customers who stay with or switch to alternative electric suppliers after December 31, 2005 to return to utility services, and requiring them to pay current market rates upon return, - establishing reliability standards that all electric suppliers must follow, - requiring utilities and alternative electric suppliers to maintain a 15 percent power reserve margin, - creating a service charge to fund the Low Income and Energy Efficiency Fund, - giving kindergarten through twelfth-grade schools a discount of 10 percent to 20 percent on electric rates, and - authorizing a service charge payable by all customers for meeting Clean Air Act requirements. In September 2004, the Chair of the Senate Technology and Energy Committee formed a workgroup, to analyze the merits of the proposed legislation. Workgroup activities have since concluded and their impact on the proposed legislation is still uncertain. In October 2004, a substitute to one of the bills was introduced, but has not yet been adopted by the Michigan Senate. Securitization: In March 2003, we filed an application with the MPSC seeking approval to issue additional Securitization bonds. In June 2003, the MPSC issued a financing order authorizing the issuance of Securitization bonds in the amount of $554 million. We filed for rehearing and clarification on a number of features in the financing order. In October 2004, the MPSC issued an order that reversed the June 2003 financing order and denied our request to issue additional Securitization bonds. Clean Air Act costs, originally included in our Stranded Cost filings, were also part of this Securitization request that was denied. The MPSC order, however, also gave us the option to file for recovery of these costs through a Section 10d(4) Regulatory Asset case, which we filed in October 2004. Stranded Costs: To the extent we experience net Stranded Costs as determined by the MPSC, the Customer Choice Act allows us to recover such costs by collecting a transition surcharge from customers who switch to an alternative electric supplier. We cannot predict whether the Stranded Cost recovery method ultimately adopted by the MPSC will be applied in a manner that will offset fully any associated margin loss. In July 2004, the ALJ issued a Proposal for Decision in our 2002 net Stranded Cost case, which recommended that the MPSC find that we incurred net Stranded Costs of $12 million. This recommendation includes the cost of money through July 2004 and excludes Clean Air Act costs. In July 2004, the MPSC Staff filed a position on our 2003 net Stranded Cost application, which resulted in a Stranded Cost calculation of $52 million. This amount includes the cost of money, but excludes Clean Air CMS-31 CMS Energy Corporation Act costs. We cannot predict how the MPSC will rule on these requests for the recovery of Stranded Costs. Therefore, we have not recorded regulatory assets to recognize the future recovery of such costs. Implementation Costs: Following an appeal and remand of initial MPSC orders relating to 1999 implementation costs, the MPSC authorized the recovery of all previously approved implementation costs for the years 1997 through 2001 by surcharges on all customers' bills phased in as rate caps expire. Authorized recoverable implementation costs totaled $88 million. This total includes the cost of money through 2003. Additional carrying costs will be added until collection occurs. For additional information on rate caps, see "Rate Caps" within this section. Our applications for recovery of $7 million of implementation costs for 2002 and $1 million for 2003 are presently pending approval by the MPSC. In September 2004, the ALJ issued a Proposal for Decision recommending full recovery of these costs. Included in the 2002 request is $5 million related to our former participation in the development of the Alliance RTO. Although we believe these implementation costs and associated cost of money are fully recoverable in accordance with the Customer Choice Act, we cannot predict the amount, if any, the MPSC will approve as recoverable. In addition to seeking MPSC approval for these costs, we are pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million for implementation costs related to our former participation in the development of the Alliance RTO. Included in this amount is $5 million pending approval by the MPSC as part of the 2002 implementation costs application. The FERC has denied our request for reimbursement and we are appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. We cannot predict the outcome of the appeal process or the amount, if any, we will collect for Alliance RTO development costs. Security Costs: The Customer Choice Act, as amended, allows for recovery of new and enhanced security costs as a result of federal and state regulatory security requirements incurred before January 1, 2006. In August 2004, the MPSC approved a settlement agreement that authorizes full recovery of $25 million in requested security costs over a five-year period beginning in September 2004. The amount includes reasonable and prudent security enhancements through December 31, 2005. All retail customers, except customers of alternative electric suppliers, will pay these charges. As a result, in August 2004, we recorded total approved security costs incurred to date, including the cost of money. As of September 30, 2004, we have recorded $21 million in security costs as a regulatory asset. Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze-cap periods, including the cost of money. In October 2004, we filed an application with the MPSC seeking recovery of $628 million of capital expenditures in excess of depreciation, Clean Air Act costs, and other expenses for the period June 2000 through December 2005. Of the $628 million, $152 million relates to the cost of money. Also included in this application is $74 million of costs that were also incorporated in our Stranded Costs filings. We cannot predict the amount, if any, the MPSC will approve as recoverable. Rate Caps: The Customer Choice Act imposes certain limitations on electric rates that could result in us being unable to collect our full cost of conducting business from electric customers. Such limitations include: - rate caps effective through December 31, 2004 for small commercial and industrial customers, and - rate caps effective through December 31, 2005 for residential customers. CMS-32 CMS Energy Corporation As a result, we may be unable to maintain our profit margins in our electric utility business during the rate cap periods. In particular, if we need to purchase power supply from wholesale suppliers while retail rates are capped, the rate restrictions may preclude full recovery of purchased power and associated transmission costs. PSCR: The PSCR process provides for the reconciliation of actual power supply costs with power supply revenues. This process provides for recovery of all reasonable and prudent power supply costs actually incurred by us, including the actual cost for fuel, and purchased and interchange power. In September 2003, we submitted a PSCR filing to the MPSC that reinstates the PSCR process for customers whose rates are no longer frozen or capped as of January 1, 2004. The proposed PSCR charge allows us to recover a portion of our increased power supply costs from large commercial and industrial customers and, subject to the overall rate caps, from other customers. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. In October 2004, the ALJ issued a Proposal for Decision, which recommended approval of our 2004 PSCR factor with minor adjustments. The PSCR factor recommended for approval includes nitrogen oxide emissions allowance costs and requested transmission costs, less a minor adjustment. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $32 million in 2004. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from all other customers. Unless we receive an order from the MPSC, we expect to self-implement this proposed 2005 PSCR charge in January 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings. Special Contracts: We entered into multi-year electric supply contracts with certain industrial and commercial customers. The contracts provide electricity at specially negotiated prices that are at a discount from tariff prices, but above our incremental cost of service. As of October 2004, special contracts for approximately 630 MW of load are in place, most of which are in effect through 2005. Transmission Costs: In May 2002, we sold our electric transmission system for $290 million to MTH. We are currently in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized by approximately $2 million to $3 million. There are multiple proceedings and a proposed rulemaking pending before the FERC regarding transmission pricing mechanisms and standard market design for electric bulk power markets and transmission. The results of these proceedings and proposed rulemakings could affect significantly: - transmission cost trends, - delivered power costs to us, and - delivered power costs to our retail electric customers. As part of the ongoing development of regional transmission systems, the issue of the appropriate level of "through and out" rates has been raised by the FERC in recent orders. Through and out rates occur when a utility purchases electricity that travels through the service territory of other utilities. These utilities charge a rate for the energy going through and out of their service territory. In March 2004, the FERC accepted a settlement whereby, effective December 1, 2004, regional through and out rates for transactions in PJM CMS-33 CMS Energy Corporation and MISO would be eliminated. In October 2004, two pricing proposals designed to replace the elimination of through and out rates were submitted to the FERC for approval. One of the pricing proposals could cause us to incur higher transmission costs. We are unable to determine if the FERC will accept either proposal, or will adopt a proposal of its own. The financial impact of such proceedings, rulemaking, and trends are not quantifiable currently. Transmission Market Developments: The MISO is scheduled to begin the Midwest energy market on March 1, 2005. At that time, the MISO will begin providing day-ahead and real-time energy market information for the MISO's participants. These services are anticipated to ensure that load requirements in the region are met reliably and efficiently, to better manage congestion on the grid, and to produce consumer savings through the centralized dispatch of generation throughout the region. The MISO is expected to provide other functions, including long-term regional planning and market monitoring. We are also evaluating whether or not there may be impacts on electric reliability associated with changes in the composition of transmission markets. For example, Commonwealth Edison Company joined the PJM RTO effective May 1, 2004 and American Electric Power Service Corporation joined the PJM RTO effective October 1, 2004. These integrations could create different patterns of flow and power within the Midwest area and could affect adversely our ability to provide reliable service to our customers. We are presently evaluating what financial impacts, if any, these market developments will have on our operations. August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid serving parts of the Midwest and the Northeast experienced a significant disturbance that impacted electric service to millions of homes and businesses. As a result, federal and state investigations regarding the cause of the blackout were conducted. These investigations resulted in the NERC and the U.S. and Canadian Power System Outage Task Force releasing electric operations recommendations. Few of the recommendations apply directly to us, since we are not a transmission owner. However, the recommendations could result in increased transmission costs to us and require upgrades to our distribution system. The financial impacts of these recommendations are not quantifiable currently. For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Uncertainties, "Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric Utility Rate Matters." PALISADES PLANT OUTAGE: Our Palisades plant is currently undergoing a regularly scheduled refueling outage. In conjunction with this scheduled outage, we have completed inspection of all 54 nuclear reactor vessel head penetrations. Small cracks were identified in the welds on two of the 45 control rod drive penetration nozzles. No external primary coolant system leakage or damage to the reactor head material was noted. Sections of the two penetrations have been removed and replaced. Post-weld testing, restoration of the support attachments, and reactor head installation on the vessel are in progress and are expected to be complete by mid-November. The total outage extension caused by the weld cracks will be approximately four weeks. The plant is expected to return to service by the end of November. For additional details on the Palisades outage, see Note 3, Uncertainties, "Other Consumers' Electric Utility Uncertainties - Nuclear Matters." UNIT OUTAGE: In June 2004, our 638 MW Karn Unit 4 facility located in Essexville, Michigan experienced a failure on the exciter. The exciter is a device that provides the magnetic field to the main electric generator. We rented a temporary replacement from Detroit Edison. In October 2004, we decided to extend our rental of the temporary replacement until December 2004 during the refueling outage at our CMS-34 CMS Energy Corporation Palisades plant, as discussed in "Palisades Plant Outage" within this section. FERC REVISED MARKET POWER TEST: In April 2004, the FERC adopted two new generation market power screen tests and modified measures that can be taken to mitigate market power where it is found. The screens will apply to all initial market-based rate applications and will be reviewed every three years. Based on our filing with the FERC in August 2004, we determined that Consumers passed the established screens, enabling us to sell power at market-based rates. Subsequent to this filing, the FERC staff informally requested a revised market power analysis based on the consolidated figures of Consumers and CMS Energy's Michigan subsidiaries. On October 1, 2004, we submitted the revised market power analysis, which we believe demonstrates that we passed the established screens on a consolidated basis. On October 29, 2004, the FERC staff requested us to provide additional support information and respond to several clarification questions. The FERC also issued similar letters to ten other companies that had made contemporaneous market power filings with the FERC. We are in the process of preparing our response, which is due November 19, 2004. BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of Appeals upheld a lower court decision that requires Detroit Edison to obey a municipal ordinance enacted by the City of Taylor, Michigan. The ordinance requires Detroit Edison to bury a section of its overhead power lines at its own expense. Consumers and other interested parties are considering appeals to the Michigan Supreme Court. Unless overturned by the Michigan Supreme Court, the decision could encourage other municipalities to adopt similar ordinances. This case has potentially broad ramifications for the electric utility and telephone industries in Michigan; however, at this time, we cannot predict the outcome of this matter. PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The standards relate to restoration after outages, safety, and customer services. The MPSC order calls for financial penalties in the form of customer credits if the standards for the duration and frequency of outages are not met. We met or exceeded all approved standards for year-end results for both 2002 and 2003. As of September 2004, we are in compliance with the acceptable level of performance. We are a member of an industry coalition that has appealed the customer credit portion of the performance standards to the Michigan Court of Appeals. We cannot predict the likely effects of the financial penalties, if any, nor can we predict the outcome of the appeal. Likewise, we cannot predict our ability to meet the standards in the future or the cost of future compliance. For additional details on performance standards, see Note 3, Uncertainties, "Consumers' Electric Utility Rate Matters - Performance Standards." GAS UTILITY BUSINESS OUTLOOK GROWTH: Over the next five years, we expect gas deliveries to grow at an average rate of less than one percent per year. Actual gas deliveries in future periods may be affected by: - fluctuations in weather patterns, - use by independent power producers, - competition in sales and delivery, - Michigan economic conditions, - gas consumption per customer, and - increases in gas commodity prices. In February 2004, we filed an application with the MPSC for a Certificate of Public Convenience and Necessity for the construction of a 25-mile gas transmission pipeline in northern Oakland County. The project is necessary to meet peak load beginning in the winter of 2005 through 2006. If we are unable to construct the pipeline due to local opposition, we will need to pursue more costly alternatives or possibly curtail serving the system's load growth in that area. We are currently involved in settlement discussions with several intervenors. At this time, we cannot predict the outcome of our negotiations. CMS-35 CMS Energy Corporation GAS UTILITY BUSINESS UNCERTAINTIES Several gas business trends or uncertainties may affect our financial results and conditions. These trends or uncertainties could have a material impact on net sales, revenues, or income from gas operations. The trends and uncertainties include: Regulatory - inadequate regulatory response to applications for requested rate increases, - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, and - proposed distribution integrity rules and mandates. Environmental - potential environmental remediation costs at a number of sites, including sites formerly housing manufactured gas plant facilities. Other - transmission pipeline integrity mandates, maintenance and remediation costs, and - other pending litigation. GAS BTU CONTENT: We sell gas to retail customers under tariffs approved by the MPSC. These tariffs measure the volume of gas delivered to customers (i.e. mcf). However, we purchase gas for resale on a heating value (i.e. Btu) basis. The Btu content of the gas purchased fluctuates and may result in customers using less gas for the same heating requirement. We fully recover our cost to purchase gas through the approved GCR. However, since the customer may use less gas on a volumetric basis, the revenue from the distribution charge (the non-gas cost portion of the customer bill) could be reduced. This could adversely affect our gas utility earnings. The amount of any possible earnings loss due to fluctuating Btu content in future periods cannot be estimated at this time. GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an order rejecting our filing to assess certain rates for non-physical gas title tracking services we provide. In December 2003, the FERC ruled that no refunds were at issue and we reversed a $4 million reserve related to this matter. In January 2004, three companies filed with the FERC for clarification or rehearing of the FERC's December 2003 order. In April 2004, the FERC issued its Order Granting Clarification. In that order, the FERC indicated that its December 2003 order was in error. It directed us to file within 30 days a fair and equitable title-tracking fee and to make refunds, with interest, to customers based on the difference between the accepted fee and the fee paid. In response to the FERC's April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further Consideration in June 2004. We expect the FERC to issue an order on the merits of this proceeding. We believe that with respect to the FERC jurisdictional transportation, we have not charged any customers title transfer fees, so no refunds are due. At this time, we cannot predict the outcome of this proceeding. GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers for our actual cost of purchased natural gas. The GCR process is designed to allow us to recover all of our prudently incurred gas costs. The MPSC reviews these costs for prudency in an annual reconciliation proceeding. The following table summarizes our GCR reconciliation filings with the MPSC. For additional details, see Note 3, Uncertainties, "Consumers' Gas Utility Rate Matters - Gas Cost Recovery." CMS-36 CMS Energy Corporation
GAS COST RECOVERY RECONCILIATION ------------------------------------------------------------------------------------------------------ Net Over GCR Year Date Filed Order Date Recovery Status ------------------------------------------------------------------------------------------------------ 2001-2002 June 2002 May 2004 $3 million $2 million has been refunded; $1 million is included in our 2003-2004 GCR reconciliation filing 2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest accrued through March 2003 and an $11 million disallowance settlement agreement 2003-2004 June 2004 Pending $28 million Filing includes the $1 million and $5 million GCR net overrecovery above ======================================================================================================
Net overrecovery amounts included in the table above include refunds received by us from our suppliers and required by the MPSC to be refunded to our customers. GCR plan for year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding. Recent increases in gas prices could cause us to incur costs in excess of what can be recovered pursuant to the current ceiling price. We are permitted to apply to the MPSC to modify the ceiling price, and will do so if necessary. In addition, if actual, prudently incurred costs exceed the ceiling price, the difference can be recovered through the reconciliation proceeding. Our GCR factor for the billing month of November 2004 is $6.55 per mcf. 2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. On December 18, 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes. On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon receipt of a letter signed by the Chairman of Consumers and CMS Energy, which agrees to: - achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached, - make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted, - refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate, - prepare and file annual reports that address certain issues identified in the order, and - file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect). On October 15, 2004, Consumers' and CMS Energy's Chairman filed a letter with the MPSC making the commitments required by the rate order. CMS-37 CMS Energy Corporation On October 19, 2004, we filed rehearing petitions with the MPSC, which seek clarification of the method of computing our rate of return on common equity. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003 the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case. On October 14, 2004, the MPSC issued its Opinion and Order in our gas depreciation case. The order restores depreciation rates to the levels that were in effect prior to the issuance of the December 18, 2003 interim gas rate order. The final order further requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to have book depreciation rates restored to the level set forth in the MPSC's prior interim gas rate relief order. GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. We expect our remaining remedial action costs to be between $37 million and $90 million. We expect to fund most of these costs through insurance proceeds and through the MPSC approved rates charged to our customers. 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. For additional details, see Note 3, Uncertainties, "Consumers' Gas Utility Contingencies - Gas Environmental Matters." OTHER CONSUMERS' OUTLOOK CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that applies to utilities and alternative electric suppliers. The code of conduct seeks to prevent financial support, information sharing, and preferential treatment between a utility's regulated and non-regulated services. The new code of conduct is broadly written and could affect our: - retail gas business energy related services, - retail electric business energy related services, - marketing of non-regulated services and equipment to Michigan customers, and - transfer pricing between our departments and affiliates. We appealed the MPSC orders related to the code of conduct and sought a deferral of the orders until the appeal was complete. We also sought waivers available under the code of conduct to continue utility activities that provide approximately $50 million in annual electric and gas revenues. In October 2002, the MPSC denied waivers for three programs including the appliance service plan offered by us, which generated $34 million in gas revenue in 2003. In March 2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code of conduct without modification. We filed an application for leave to appeal with the Michigan Supreme Court, but we cannot predict whether the Michigan Supreme Court will accept the case or the outcome of any appeal. In April 2004, the Michigan Governor signed legislation that allows us to remain in the appliance service business. MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV CMS-38 CMS Energy Corporation Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund (net of approximately $16 million of deferred expenses) has not been recognized in year-to-date 2004 earnings. ENTERPRISES OUTLOOK INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our IPP business by narrowing the focus of our operations to primarily North America and the Middle East/North Africa. We will continue to sell designated assets and investments that are under-performing or are not consistent with this focus. CMS ERM: CMS ERM has streamlined its portfolio in order to reduce business risk and outstanding credit guarantees. Our future activities will be centered on fuel procurement activities and merchant power marketing in such a way as to optimize the earnings from our IPP generation assets. CMS GAS TRANSMISSION: CMS Gas Transmission has completed its plan to sell the majority of its international assets and businesses. Future operations will be conducted mainly in Michigan and South America. 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., which is not included in our consolidated financial statements. 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. The financial performance is dependent primarily on the number of new wells connected and transportation volumes, with certain EBITDA thresholds required to be achieved in order for us to receive payments on the note. There may not be enough new wells connected in 2004 to achieve the annual threshold and thus trigger a payment on the note for 2004. UNCERTAINTIES: The results of operations and the financial position of our diversified energy businesses may be affected by a number of trends or uncertainties. Those that could have a material impact on our income, cash flows, or balance sheet and credit improvement include: - our ability to sell or to improve the performance of assets and businesses in accordance with our business plan, - changes in exchange rates or in local economic or political conditions, particularly in Argentina, Venezuela, Brazil, and the Middle East, - changes in foreign laws or in governmental or regulatory policies that could reduce significantly the tariffs charged and revenues recognized by certain foreign subsidiaries, or increase expenses, - imposition of stamp taxes on South American contracts that could increase project expenses substantially, - impact of any future rate cases, FERC actions, or orders on regulated businesses, - impact of ratings downgrades on our liquidity, operating costs, and cost of capital, - impact of 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, and CMS-39 CMS Energy Corporation - limited available gas supplies or Argentine government regulations could restrict natural gas exports to our GasAtacama generating plant. OTHER OUTLOOK TAX BILL: In October 2004, Congress passed tax legislation, the "American Jobs Creation Act of 2004," which the President signed into law. The bill contains several provisions that could impact us, including a tax credit for the production of electricity from biomass and a one-time reduction in the effective tax rate (from 35 percent to 5.25 percent) on dividends repatriated in 2005 from foreign subsidiaries. We are currently studying the tax bill's provisions for its impact to us, which we believe will be positive in 2004 and following years. SARBANES-OXLEY ACT OF 2002: We are in the process of implementing the internal control requirements mandated by the Sarbanes-Oxley Act. Our evaluation and testing of internal controls is continuing, but is incomplete as of the date of this Form 10-Q. We are currently unaware of any material weaknesses in our control over financial reporting. We plan to complete testing and finalize our evaluation in the fourth quarter. Until this is completed, we cannot provide assurance that our internal controls do not contain material weaknesses. Our 2004 Form 10-K will contain a report by our management on the effectiveness of our internal controls and a report by Ernst & Young, our Registered Independent Auditors, that attests to and reports on our management's assessment of internal control. These annual reports on internal control are now required by Section 404 of the Sarbanes-Oxley Act for all public companies, effective with our 2004 Form 10-K. LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an investigation by the DOJ regarding round-trip trading transactions by CMS MST. Additionally, we are named as a party in various litigation including a shareholder derivative lawsuit, a securities class action lawsuit, a class action lawsuit alleging ERISA violations, several lawsuits regarding alleged false natural gas price reporting and price manipulation, and a lawsuit surrounding the possible sale of CMS Pipeline Assets. For additional details regarding these investigations and litigation, see Note 3, Uncertainties. NEW ACCOUNTING STANDARDS FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The FASB issued this Interpretation in January 2003. The objective of the Interpretation is to assist in determining when one party controls another entity in circumstances where a controlling financial interest cannot be properly identified based on voting interests. Entities with this characteristic are considered variable interest entities. The Interpretation requires the party with the controlling financial interest, known as the primary beneficiary, in a variable interest entity to consolidate the entity. In December 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that have not previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No. 46 provided an implementation deferral until the first quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation No. 46 for all entities. We determined that we are the primary beneficiary of both the MCV Partnership and the FMLP. We have a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the MCV Facility, which results in Consumers holding a 35 percent lessor interest in the MCV Facility. Collectively, these interests CMS-40 make us the primary beneficiary of these entities. As such, we consolidated their assets, liabilities, and activities into our financial statements for the first time as of and for the quarter ended March 31, 2004. These partnerships have third-party obligations totaling $581 million at September 30, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.440 billion at September 30, 2004. The creditors of these partnerships do not have recourse to the general credit of CMS Energy. At December 31, 2003, we determined that we are the primary beneficiary of three other entities that are determined to be variable interest entities. We have 50 percent partnership interest 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 as defined by the Interpretation. Therefore, we consolidated these partnerships into our consolidated financial statements for the first time as of December 31, 2003. These partnerships have third-party obligations totaling $116 million at September 30, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $168 million as of September 30, 2004. Other than 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. We also determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities have been deconsolidated as of December 31, 2003. Company Obligated Trust Preferred Securities totaling $663 million, that were previously included in mezzanine equity, have been eliminated due to deconsolidation. As a result of the deconsolidation, we reflected $684 million of long-term debt-related parties and reflected an investment in related parties of $21 million. We are not required to restate prior periods for the impact of this accounting change. Additionally, we have variable interest entities in which we are not the primary beneficiary. FASB Interpretation No. 46 requires us to disclose certain information about these entities. The following chart details our involvement in these entities at September 30, 2004:
Investment Total Name (Ownership Nature of the Involvement Balance Operating Agreement Generating Interest) Entity Country Date (In Millions) with CMS Energy Capacity ------------------------------------------------------------------------------------------------------------------------- Taweelah (40%) Generator United Arab 1999 $ 77 Yes 777 MW Emirates Jubail (25%) Generator - Saudi Arabia 2001 $ - Yes 250 MW Under Construction Shuweihat (20%) Generator United Arab 2001 $ 51(a) Yes 1,500 MW Emirates ------------------------------------------------------------------------------------------------------------------------- Total $ 128 2,527 MW =========================================================================================================================
(a) At September 30, 2004, the balance includes our proportionate share of the negative fair value of derivative instruments of $26 million. CMS-41 CMS Energy Corporation Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $128 million, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $59 million. In the third quarter of 2004, we contributed an investment of $70 million in Shuweihat. The contribution was made pursuant to the Shuweihat Shareholders' Agreement, which was entered into in 2001. FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003, we elected a one-time deferral of the accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1. The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position, No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position, No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations and postretirement benefit costs should reflect the effects of the Act. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $158 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $18 million for the nine months ended September 30, 2004, and an expected total reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost in accordance with regulatory accounting. As such, the remeasurement resulted in a net reduction of OPEB expense of $4 million, or $0.03 per share, for the three months ended September 30, 2004, $13 million, or $0.08 per share, for the nine months ended September 30, 2004, and an expected total net expense reduction of $17 million for 2004. NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE EITF ISSUE NO. 03-1, THE MEANING OF OTHER THAN TEMPORARY INVESTMENTS: The issue addresses the definition of an other than temporary impairment of certain investments and was scheduled to be effective as of September 30, 2004. The scope of EITF Issue No. 03-1 includes debt and equity securities accounted for under SFAS No. 115, debt and equity securities held by non-profit organizations under SFAS No. 124, and cost method investments under APB No. 18. The FASB issued a final FASB Staff Position, FSP EITF Issue 03-1-1 deferring portions of EITF Issue No. 03-1 relating to guidance on such matters as to what constitutes a minor impairment and the determination of "other than temporary." The deferral extends until the Board issues a final FSP 03-1-a defining the effective date and amending EITF Issue No. 03-1 as it is currently written. The FASB expects to issue the FASB Staff Position in November. The deferral does not apply to the disclosure requirements of EITF Issue No. 03-1, which are required in our annual financial statements. We do not expect this issue to have an impact on our results of operations when it becomes effective. EITF ISSUE NO. 04-8, THE EFFECT OF CONTINGENTLY CONVERTIBLE DEBT ON DILUTED EARNINGS PER SHARE: At its September 2004 meeting, the EITF reached a final consensus that contingently convertible instruments should be included in the diluted earnings per share computation (if dilutive) regardless of whether the CMS-42 CMS Energy Corporation market price trigger has been met. We currently have a contingently convertible debt instrument and a contingently convertible preferred stock instrument outstanding. Both securities include similar contingent conversion provisions based on the market price of our common stock. Including the dilutive effect of these instruments could reduce our diluted earnings per share for 2004 by up to $0.10 per average common share. For further information on these securities, refer to Note 4, Financings and Capitalization, "Contingently Convertible Securities." The effective date for this EITF Issue is for reporting periods ending after December 15, 2004, and the guidance applies to contingently convertible instruments outstanding at December 31, 2004. We plan to modify our contingently convertible securities prior to the effective date, through exchange offers that are intended to mitigate the earnings per share impact. EITF ISSUE NO. 04-10, APPLYING PARAGRAPH 19 OF SFAS NO. 131, DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, IN DETERMINING WHETHER TO AGGREGATE OPERATING SEGMENTS THAT DO NOT MEET THE QUANTITATIVE THRESHOLDS: This issue addresses how to apply the operating segment aggregation criteria in SFAS No. 131. At their September 2004 meeting, the EITF reached consensus on this issue. The EITF concluded that operating segments that do not meet the quantitative thresholds established in SFAS No. 131 could be aggregated only if aggregation is consistent with the objective and basic principles of Statement 131 and the segments have similar economic characteristics. The consensus will be effective as of December 31, 2004. We are currently assessing this issue and have not determined whether it will impact our segment reporting disclosures. CMS-43 CMS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED RESTATED RESTATED SEPTEMBER 30 2004 2003 2004 2003 ------------------------------------------------------------------------------------------------------------------------- In Millions, Except Per Share Amounts OPERATING REVENUE $ 1,063 $ 1,047 $ 3,910 $ 4,141 EARNINGS FROM EQUITY METHOD INVESTEES 18 28 78 125 OPERATING EXPENSES Fuel for electric generation 215 104 571 310 Purchased and interchange power 100 118 257 459 Purchased power - related parties - 135 - 395 Cost of gas sold 142 166 1,166 1,301 Other operating expenses 225 215 667 630 Maintenance 63 50 185 169 Depreciation, depletion and amortization 114 90 366 308 General taxes 64 58 200 134 Asset impairment charges - 61 125 70 ------------------------------------------------- 923 997 3,537 3,776 ------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 158 78 451 490 OTHER INCOME (DEDUCTIONS) Accretion expense (6) (7) (18) (23) Gain (loss) on asset sales, net 46 - 49 (8) Interest and dividends 8 10 22 21 Foreign currency gains (losses), net (1) - (7) 11 Other income 15 5 42 11 Other expense (1) (7) (5) (10) ------------------------------------------------- 61 1 83 2 ------------------------------------------------------------------------------------------------------------------------- FIXED CHARGES Interest on long-term debt 124 135 380 360 Interest on long-term debt - related parties 15 - 44 - Other interest 6 31 18 49 Capitalized interest (2) (2) (5) (7) Preferred dividends of subsidiaries 2 - 4 1 Preferred securities distributions - 16 - 52 ------------------------------------------------- 145 180 441 455 ------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS 74 (101) 93 37 INCOME TAX EXPENSE (BENEFIT) 18 (25) 8 48 MINORITY INTERESTS 5 (5) 17 (3) ------------------------------------------------- INCOME (LOSS) FROM CONTINUING OPERATIONS 51 (71) 68 (8) GAIN (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $4 AND $3 TAX EXPENSE IN 2004 AND $5 TAX BENEFIT AND $16 TAX EXPENSE IN 2003 8 2 6 (20) ------------------------------------------------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING 59 (69) 74 (28) CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13 TAX BENEFIT IN 2003: DERIVATIVES (NOTE 6) - - - (23) ASSET RETIREMENT OBLIGATIONS, SFAS NO. 143 (NOTE 10) - - - (1) ------------------------------------------------- - - - (24) ------------------------------------------------- NET INCOME (LOSS) 59 (69) 74 (52) PREFERRED DIVIDENDS 3 - 9 - ------------------------------------------------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCK $ 56 $ (69) $ 65 $ (52) =================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-44
THREE MONTHS ENDED NINE MONTHS ENDED RESTATED RESTATED SEPTEMBER 30 2004 2003 2004 2003 ------------------------------------------------------------------------------------------------------------------- In Millions, Except Per Share Amounts CMS ENERGY NET INCOME (LOSS) Net Income (Loss) Available to Common Stock $ 56 $ (69) $ 65 $ (52) ====================================== BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE Income (Loss) from Continuing Operations $0.30 $(0.47) $0.36 $(0.06) Income (Loss) from Discontinued Operations 0.05 0.01 0.04 (0.14) Loss from Changes in Accounting - - - (0.16) -------------------------------------- Net Income (Loss) Attributable to Common Stock $0.35 $(0.46) $0.40 $(0.36) ====================================== DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE Income (Loss) from Continuing Operations $0.29 $(0.47) $0.36 $(0.06) Income (Loss) from Discontinued Operations 0.05 0.01 0.04 (0.14) Loss from Changes in Accounting - - - (0.16) -------------------------------------- Net Income (Loss) Attributable to Common Stock $0.34 $(0.46) $0.40 $(0.36) ====================================== DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ - $ - -------------------------------------------------------------------------------------------------------------------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-45 CMS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
NINE MONTHS ENDED RESTATED SEPTEMBER 30 2004 2003 ------------------------------------------------------------------------------------------------- In Millions CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 74 $ (52) Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation, depletion and amortization (includes nuclear 366 308 decommissioning of $4 and $4, respectively) Loss (gain) on disposal of discontinued operations (Note 2) (7) 46 Asset impairments (Note 2) 125 70 Capital lease and debt discount amortization 18 16 Accretion expense 18 23 Bad debt expense 11 17 Undistributed earnings from related parties (57) (45) Loss (gain) on the sale of assets (Note 2) (49) 8 Cumulative effect of accounting changes - 24 Pension contribution - (210) Changes in other assets and liabilities: Decrease in accounts receivable and accrued revenues 16 327 Increase in inventories (273) (354) Increase (decrease) in accounts payable 18 (180) Decrease in accrued expenses (82) (206) Deferred income taxes and investment tax credit 61 56 Decrease (increase) in other current and non-current assets (60) 461 Increase (decrease) in other current and non-current liabilities 15 (309) ------------------ Net cash provided by operating activities $ 194 $ - ------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excludes assets placed under capital lease) $(377) $ (356) Investments in partnerships and unconsolidated subsidiaries (70) - Cost to retire property (53) (52) Restricted cash (Note 1) 118 (167) Investment in Electric Restructuring Implementation Plan (5) (5) Investments in nuclear decommissioning trust funds (4) (4) Proceeds from nuclear decommissioning trust funds 35 26 Maturity of MCV restricted investment securities held-to-maturity 592 - Purchase of MCV restricted investment securities held-to-maturity (592) - Proceeds from sale of assets 215 848 Other investing 9 42 ------------------ Net cash provided by (used in) investing activities $(132) $ 332 ------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from notes, bonds, and other long-term debt $ 839 $ 2,302 Issuance of common stock - 229 Retirement of bonds and other long-term debt (997) (1,830) Retirement of trust preferred securities - (220) Payment of preferred stock dividends (9) - Decrease in notes payable - (487) Payment of capital lease obligations (41) (10) ------------------ Net cash used in financing activities $(208) $ (16) ------------------------------------------------------------------------------------------------- EFFECT OF EXCHANGE RATES ON CASH - 2 ------------------------------------------------------------------------------------------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $(146) $ 318 CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB INTERPRETATION NO. 46 CONSOLIDATION 174 - CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 532 351 ----------------- CASH AND CASH EQUIVALENTS, END OF PERIOD $ 560 $ 669 =================================================================================================
CMS-46
NINE MONTHS ENDED RESTATED SEPTEMBER 30 2004 2003 ------------------------------------------------------------------------------------------------------ In Millions OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE: CASH TRANSACTIONS Interest paid (net of amounts capitalized) $ 429 $ 405 Income taxes paid (net of refunds) - (33) OPEB cash contribution 48 58 NON-CASH TRANSACTIONS Other assets placed under capital leases $ 2 $ 11 ======================================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-47 CMS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS
ASSETS SEPTEMBER 30 SEPTEMBER 30 2003 2004 DECEMBER 31 RESTATED (UNAUDITED) 2003 (UNAUDITED) --------------------------------------------------------------------------------------------------------------- In Millions PLANT AND PROPERTY (AT COST) Electric utility $ 7,860 $ 7,600 $ 7,583 Gas utility 2,929 2,875 2,841 Enterprises 3,400 895 680 Other 28 32 31 ------------------------------------------ 14,217 11,402 11,135 Less accumulated depreciation, depletion and amortization 6,035 4,846 4,882 ------------------------------------------ 8,182 6,556 6,253 Construction work-in-progress 418 388 371 ------------------------------------------ 8,600 6,944 6,624 --------------------------------------------------------------------------------------------------------------- INVESTMENTS Enterprises 731 724 769 Midland Cogeneration Venture Limited Partnership - 419 404 First Midland Limited Partnership - 224 222 Other 24 23 2 ------------------------------------------ 755 1,390 1,397 --------------------------------------------------------------------------------------------------------------- CURRENT ASSETS Cash and cash equivalents at cost, which approximates market 560 532 669 Restricted cash 83 201 205 Accounts receivable, notes receivable, and accrued revenue, less allowances of $37, $40 and $33, respectively 392 378 264 Accounts receivable and notes receivable - related parties 57 73 164 Inventories at average cost: Gas in underground storage 996 741 815 Materials and supplies 112 110 102 Generating plant fuel stock 78 41 44 Assets held for sale - 24 22 Price risk management assets 113 102 80 Regulatory assets 19 19 19 Derivative instruments 143 2 2 Prepayments and other 251 246 268 ------------------------------------------ 2,804 2,469 2,654 --------------------------------------------------------------------------------------------------------------- NON-CURRENT ASSETS Regulatory Assets Securitized costs 616 648 659 Postretirement benefits 145 162 168 Abandoned Midland Project 10 10 10 Other 368 266 257 Assets held for sale - 2 52 Price risk management assets 229 177 179 Nuclear decommissioning trust funds 551 575 553 Prepaid pension costs 372 388 - Goodwill 28 25 40 Notes receivable - related parties 219 242 129 Notes receivable 172 150 146 Other 508 390 366 ------------------------------------------ 3,218 3,035 2,559 ------------------------------------------ TOTAL ASSETS $ 15,377 $ 13,838 $ 13,234 ===============================================================================================================
CMS-48 STOCKHOLDERS' INVESTMENT AND LIABILITIES
ASSETS SEPTEMBER 30 SEPTEMBER 30 2003 2004 DECEMBER 31 RESTATED (UNAUDITED) 2003 (UNAUDITED) --------------------------------------------------------------------------------------------------------------- In Millions CAPITALIZATION Common stockholders' equity Common stock, authorized 350.0 shares; outstanding 161.9 shares, 161.1 shares and 161.1 shares, respectively $ 2 $ 2 $ 2 Other paid-in-capital 3,850 3,846 3,834 Accumulated other comprehensive loss (309) (419) (693) Retained deficit (1,779) (1,844) (1,852) ------------------------------------------- 1,764 1,585 1,291 Preferred stock of subsidiary 44 44 44 Preferred stock 261 261 - Company-obligated convertible Trust Preferred Securities of subsidiaries - - 173 Company-obligated mandatorily redeemable Trust Preferred Securities of Consumers' subsidiaries - - 490 Long-term debt 6,228 6,020 6,295 Long-term debt - related parties 684 684 - Non-current portion of capital and finance lease obligations 318 58 116 ------------------------------------------- 9,299 8,652 8,409 --------------------------------------------------------------------------------------------------------------- MINORITY INTERESTS 750 73 35 --------------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Current portion of long-term debt, capital and finance leases 594 519 186 Notes payable - - 4 Accounts payable 338 317 361 Accounts payable - related parties 1 40 50 Accrued interest 128 130 112 Accrued taxes 192 285 151 Liabilities held for sale - 2 - Price risk management liabilities 106 89 70 Current portion of purchase power contracts 6 27 26 Current portion of gas supply contract obligations 31 29 28 Deferred income taxes 30 27 16 Other 281 185 193 ------------------------------------------- 1,707 1,650 1,197 --------------------------------------------------------------------------------------------------------------- NON-CURRENT LIABILITIES Regulatory Liabilities Cost of removal 1,026 983 962 Income taxes, net 326 312 309 Other 160 172 152 Postretirement benefits 247 265 590 Deferred income taxes 658 615 441 Deferred investment tax credit 81 85 86 Asset retirement obligation 438 359 363 Liabilities held for sale - - - Price risk management liabilities 226 175 175 Gas supply contract obligations 186 208 218 Power purchase agreement - MCV Partnership - - 8 Other 273 289 289 ------------------------------------------- 3,621 3,463 3,593 --------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES (Notes 1, 3 and 4) TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $ 15,377 $ 13,838 $ 13,234 ===============================================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-49 CMS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED RESTATED RESTATED SEPTEMBER 30 2004 2003 2004 2003 --------------------------------------------------------------------------------------------------------------------------------- In Millions COMMON STOCK At beginning of period $ 2 $ 1 $ 2 $ 1 Common stock issued - 1 - 1 ------------------------------------------ At end of period 2 2 2 2 --------------------------------------------------------------------------------------------------------------------------------- OTHER PAID-IN CAPITAL At beginning of period 3,848 3,608 3,846 3,605 Common stock reacquired (4) (4) (5) (5) Common stock reissued - 1 - 1 Common stock issued 6 229 9 233 ------------------------------------------ At end of period 3,850 3,834 3,850 3,834 --------------------------------------------------------------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Minimum Pension Liability At beginning of period - (261) - (241) Minimum pension liability adjustments (a) (1) (1) (1) (21) ------------------------------------------ At end of period (1) (262) (1) (262) ------------------------------------------ Investments At beginning of period 8 5 8 2 Unrealized gain (loss) on investments (a) (1) 1 (1) 4 ------------------------------------------ At end of period 7 6 7 6 ------------------------------------------ Derivative Instruments At beginning of period 6 (22) (8) (31) Unrealized gain on derivative instruments (a) 5 9 24 2 Reclassification adjustments included in consolidated net income (loss) (a) (1) (5) (6) 11 ------------------------------------------ At end of period 10 (18) 10 (18) ------------------------------------------ Foreign Currency Translation At beginning of period (327) (412) (419) (458) Change in foreign currency translation (a) 2 (7) 94 39 ------------------------------------------ At end of period (325) (419) (325) (419) ------------------------------------------ At end of period (309) (693) (309) (693) --------------------------------------------------------------------------------------------------------------------------------- RETAINED DEFICIT At beginning of period (1,835) (1,783) (1,844) (1,800) Net income (loss) (a) 59 (69) 74 (52) Preferred stock dividends declared (3) - (9) - Common stock dividends declared - - - - ------------------------------------------ At end of period (1,779) (1,852) (1,779) (1,852) ------------------------------------------ TOTAL COMMON STOCKHOLDERS' EQUITY $ 1,764 $ 1,291 $ 1,764 $ 1,291 ================================================================================================================================= (A) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS): Minimum Pension Liability Minimum pension liability adjustments, net of tax benefit of $(1), $(1), $(1) and $(11), respectively $ (1) $ (1) $ (1) $ (21) Investments Unrealized gain (loss) on investments, net of tax (tax benefit) of $-, $1, $- and $2, respectively (1) 1 (1) 4 Derivative Instruments Unrealized gain on derivative instruments, net of tax (tax benefit) of $7, $-, $14 and $2, respectively 5 9 24 2 Reclassification adjustments included in consolidated net income (loss), net of tax (tax benefit) of $-, $(4), $(3) and $7, respectively (1) (5) (6) 11 Foreign currency translation, net 2 (7) 94 39 Net income (loss) 59 (69) 74 (52) ------------------------------------------ Total Other Comprehensive Income (Loss) $ 63 $ (72) $ 184 $ (17) ==========================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-50 CMS Energy Corporation CMS ENERGY CORPORATION CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) These interim Consolidated Financial Statements have been prepared by CMS Energy in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. As such, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted. Certain prior year amounts have been reclassified to conform to the presentation in the current year. In management's opinion, the unaudited information contained in this report reflects all adjustments of a normal recurring nature necessary to assure the fair presentation of financial position, results of operations and cash flows for the periods presented. The Condensed Notes to Consolidated Financial Statements and the related Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements contained in CMS Energy's Form 10-K/A for the year ended December 31, 2003. Due to the seasonal nature of CMS Energy's operations, the results as presented for this interim period are not necessarily indicative of results to be achieved for the fiscal year. RESTATEMENT OF 2003 FINANCIAL STATEMENTS Our financial statements as of and for the three and nine months ended September 30, 2003, as presented in this Form 10-Q, have been restated for the following matters that were disclosed previously in Note 19, Quarterly Financial and Common Stock Information (Unaudited), in our 2003 Form 10-K/A: - International Energy Distribution, which includes SENECA and CPEE, is no longer considered "discontinued operations," due to a change in our expectations as to the timing of the sales, - certain derivative accounting corrections at our equity affiliates, and - the net loss recorded in the second quarter of 2003 relating to the sale of Panhandle, reflected as Discontinued Operations, was understated by approximately $14 million, net of tax. 1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES CORPORATE STRUCTURE: CMS Energy is an integrated energy company with a business strategy focused 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 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 the accounts of CMS Energy, Consumers, Enterprises, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with Revised FASB Interpretation No. 46. The primary beneficiary of a variable interest entity is the party that absorbs or receives a majority of the entity's expected losses or expected residual returns or both as a result of holding variable interests, CMS-51 CMS Energy Corporation which are ownership, contractual, or other economic interests. In 2004, we consolidated the MCV Partnership and the FMLP in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 11, Implementation of New Accounting Standards. 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. Intercompany transactions and balances have been eliminated. USE OF ESTIMATES: We prepare our financial statements in conformity with accounting principles generally accepted in the United States. We are required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates. We are required to record estimated liabilities in the 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. We have used this accounting principle to record estimated liabilities as discussed in Note 3, Uncertainties. 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. Sales taxes are recorded as liabilities and are not included in revenues. Revenues on sales of marketed electricity, natural gas, and other energy products are recognized at delivery. Mark-to-market changes in the fair values of energy trading contracts that qualify as derivatives are recognized as revenues in the periods in which the changes occur. CAPITALIZED INTEREST: We are required to 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 that is incurred, and our non-regulated businesses are prohibited from imputing interest costs on any equity funds. Our regulated businesses are permitted to capitalize an allowance for funds used during construction on regulated construction projects and to include such amounts in plant in service. CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an original maturity of three months or less are considered cash equivalents. At September 30, 2004, our restricted cash on hand was $83 million. Restricted cash primarily includes cash dedicated for repayment of bonds. It is classified as a current asset as the payments on the related bonds occur within one year. EARNINGS PER SHARE: Basic and diluted earnings per share are based on 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 earnings per share, includes the effects of dilutive stock options, warrants and convertible securities. The effect on number of shares of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable. For earnings per share computation, see Note 5, Earnings Per Share and Dividends. FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities using SFAS No. 115. Debt and equity securities can be classified into one of three categories: held-to-maturity, trading, or available-for-sale. Our debt securities are classified as held-to-maturity securities and are reported at cost. Our investments in equity securities are classified as available-for-sale securities and are reported at fair value determined from quoted market prices. Any unrealized gains or losses resulting from changes in fair value are reported in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless such changes in fair value are determined to CMS-52 CMS Energy Corporation be other than temporary. Unrealized gains or losses resulting from changes in the fair value of our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. For additional details regarding financial instruments, see Note 6, Financial and Derivative Instruments. FOREIGN CURRENCY TRANSLATION: 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. The gains or losses that result from this process, and gains and losses on intercompany foreign currency transactions that are long-term in nature that we do not intend to settle in the foreseeable future, are shown in the stockholders' equity section on our Consolidated Balance Sheets. For subsidiaries operating in highly inflationary economies, the U.S. dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those that are hedged, are included in determining net income. IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate potential impairments of our investments in 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 asset exceeds its estimated undiscounted future cash flows, an impairment loss is recognized and the asset is written down to its estimated fair value. 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 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. As of September 30, 2004, we have recorded a liability to the DOE for $140 million, including interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. The amount of this liability, excluding a portion of interest, was recovered through electric rates. For additional details on disposal of spent nuclear fuel, see Note 3, Uncertainties, "Other Consumers' Electric Utility Uncertainties - Nuclear Matters." OTHER INCOME AND OTHER EXPENSE: The following tables show the components of Other income and Other expense:
In Millions ---------------------------------------------------------------------------------------------------------------- Three Months Ended Nine Months Ended ----------------------------------------- September 30 2004 2003 2004 2003 ---------------------------------------------------------------------------------------------------------------- Other income Interest and dividends - related parties $ 2 $ 1 $ 4 $ 3 PA141 Return on capital expenditures 10 - 28 - Electric restructuring return 2 1 5 4 Investment sale gain 1 - 2 - All other - 3 3 4 ---------------------------------------------------------------------------------------------------------------- Total other income $ 15 $ 5 $ 42 $ 11 ================================================================================================================
CMS-53 CMS Energy Corporation
In Millions -------------------------------------------------------------------------------------------------------------------- Three Months Ended Nine Months Ended ------------------------------------------- September 30 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------------------- Other expense Loss on SERP investment $ (1) $ (1) $ (2) $ (2) CMS MST remediation costs - (4) - (4) Civic and political expenditures (1) - (2) (1) All other 1 (2) (1) (3) -------------------------------------------------------------------------------------------------------------------- Total other expense $ (1) $ (7) $ (5) $(10) ====================================================================================================================
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, the original cost is charged to accumulated depreciation. The cost of removal, less salvage, is recorded as a regulatory liability. For additional details, see Note 10, Asset Retirement Obligations. An allowance for funds used during construction is capitalized on regulated construction projects. With respect to the retirement or disposal of non-regulated assets, the resulting gains or losses are recognized in income. RECLASSIFICATIONS: Certain prior year amounts have been reclassified for comparative purposes. These reclassifications did not affect consolidated net income for the years presented. UTILITY REGULATION: We account for the effects of regulation based on the regulated utility accounting standard SFAS No. 71. As a result, the actions of regulators affect when we recognize revenues, expenses, assets, and liabilities. SFAS No. 144 imposes strict criteria for retention of regulatory-created assets by requiring that such assets be probable of future recovery at each balance sheet date. Management believes these assets are probable of future recovery. 2: DISCONTINUED OPERATIONS, OTHER ASSET SALES, IMPAIRMENTS, AND RESTRUCTURING Our continued focus on financial improvement has led to discontinuing operations, completing many asset sales, impairing some assets, and incurring costs to restructure our business. Gross cash proceeds received from the sale of assets totaled $215 million for the nine months ended September 30, 2004 and $848 million for the nine months ended September 30, 2003. CMS-54 CMS Energy Corporation At September 30, 2004, we no longer have "Assets held for sale." At December 31, 2003, "Assets held for sale" included Parmelia, Bluewater Pipeline, and our investment in the American Gas Index Fund. At September 30, 2003, "Assets held for sale" included Marysville, Parmelia, and CMS Land. The major classes of assets and liabilities held for sale on our Consolidated Balance Sheets are as follows:
In Millions ---------------------------------------------------------------------------------------------------------------- September 30 December 31 September 30 2004 2003 2003 ---------------------------------------------------------------------------------------------------------------- Assets Cash $ - $ 7 $ 5 Accounts receivable - 2 1 Property, plant and equipment - net - 2 44 Other - 15 24 ---------------------------------------------------------------------------------------------------------------- Total assets held for sale $ - $ 26 $ 74 ================================================================================================================ Liabilities Accounts payable $ - $ 2 $ - ---------------------------------------------------------------------------------------------------------------- Total liabilities held for sale $ - $ 2 $ - ================================================================================================================
DISCONTINUED OPERATIONS We have discontinued the following operations:
In Millions ---------------------------------------------------------------------------------------------------------------- Pretax After-tax Business/Project Discontinued Gain(Loss) Gain(Loss) Status ---------------------------------------------------------------------------------------------------------------- CMS Field Services December 2002 $ (5) $ (1) Sold July 2003 Marysville June 2003 2 1 Sold November 2003 Parmelia (a) December 2003 10 6 Sold August 2004 ================================================================================================================
(a) In August 2004, we sold our Parmelia business and our interest in Goldfields, which did not meet the criteria for discontinued operations, to APT for A$204 million (approximately $147 million in U.S. dollars). The proceeds are subject to normal post closing adjustments. The $10 million ($6 million after-tax) gain on the sale of Parmelia includes a $3 million ($2 million after-tax) foreign currency translation loss. CMS-55 CMS Energy Corporation The following amounts are reflected in the Consolidated Statements of Income (Loss), in the Gain (Loss) From Discontinued Operations line:
In Millions ------------------------------------------------------------------------------- Three months ended September 30 2004 2003 ------------------------------------------------------------------------------- Revenues $ 1 $ 5 =============================================================================== Discontinued operations: Pretax loss from discontinued operations $ - $ (1) Income tax expense - - ----------------------- Loss from discontinued operations - (1) Pretax gain (loss) from disposal of discontinued operations 12 (2) Income tax expense (benefit) 4 (5) ----------------------- Gain from disposal of discontinued operations 8 3 ------------------------------------------------------------------------------- Gain from discontinued operations $ 8 $ 2 ================================================================================
In Millions ------------------------------------------------------------------------------- Nine months ended September 30 2004 2003 ------------------------------------------------------------------------------- Revenues $ 11 $501 =============================================================================== Discontinued operations: Pretax gain (loss) from discontinued operations $ (1) $ 45 Income tax expense - 19 ----------------------- Gain (loss) from discontinued operations (1) 26 Pretax gain (loss) from disposal of discontinued operations 10 (49) Income tax expense (benefit) 3 (3) ----------------------- Gain (loss) from disposal of discontinued operations 7 (46) -------------------------------------------------------------------------------- Gain (loss) from discontinued operations $ 6 $(20) ================================================================================
The loss from discontinued operations includes a reduction in asset values, a provision for anticipated closing costs, and a portion of CMS Energy's interest expense. Interest expense of less than $1 million for the nine months ended September 30, 2004 and $22 million for the nine months ended September 30, 2003 has been allocated based on a ratio of the expected proceeds for the asset to be sold divided by CMS Energy's total capitalization of each discontinued operation multiplied by CMS Energy's interest expense. OTHER ASSET SALES Our other asset sales include the following non-strategic and under-performing assets. The impacts of these sales are included in "Gain (loss) on asset sales, net" in the Consolidated Statements of Income (Loss). For the nine months ended September 30, 2004, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations: CMS-56 CMS Energy Corporation
In Millions -------------------------------------------------------------------------------- Pretax After-tax Date sold Business/Project Gain Gain -------------------------------------------------------------------------------- February Bluewater Pipeline (a) $ 1 $ 1 April Loy Yang (b) - - May American Gas Index fund (c) 1 1 August Goldfields (d) 45 29 Various Other 2 1 -------------------------------------------------------------------------------- Total gain on asset sales $ 49 $ 32 ================================================================================
(a) Bluewater Pipeline is a 24.9-mile pipeline that extends from Marysville, Michigan to Armada, Michigan. (b) In April 2004, we and our partners sold the 2,000 MW Loy Yang power plant and adjacent coal mine in Victoria, Australia for about A$3.5 billion ($2.6 billion in U.S. dollars), including A$145 million for the project equity. Our share of the proceeds, net of transaction costs and closing adjustments, was $44 million. In anticipation of the sale, we recorded an impairment in the first quarter as discussed in "Asset Impairments" within this Note. (c) In May 2004, we sold our interest in the American Gas Index fund for $7 million. (d) In August 2004, we sold our interest in Goldfields and our Parmelia business, a discontinued operation, to APT for A$204 million (approximately $147 million in U.S. dollars). The proceeds are subject to normal post closing adjustments. The $45 million ($29 million after-tax) gain on the sale of Goldfields includes a $9 million ($6 million after-tax) foreign currency translation gain. For the nine months ended September 30, 2003, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations:
In Millions -------------------------------------------------------------------------------- Pretax After-tax Date sold Business/Project Gain Gain -------------------------------------------------------------------------------- January CMS MST Wholesale Gas $ (6) $ (4) March CMS MST Wholesale Power 2 1 June Guardian Pipeline (4) (3) ------------------- ------------------------------------------------------------ Total loss on asset sales $ (8) $ (6) ================================================================================
ASSET IMPAIRMENTS We record an asset impairment when we determine that the expected future cash flows from an asset would be insufficient to provide for recovery of the asset's carrying value. An asset held-in-use is evaluated 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. The assets written down include both domestic and foreign electric power plants, gas processing facilities, and certain equity method and other investments. CMS-57 In addition, we have written off the carrying value of projects under development that will no longer be pursued. The table below summarizes our asset impairments:
In Millions ------------------------------------------------------------------------------------------------------------- Nine months ended September 30 Pretax 2004 After-tax 2004 Pretax 2003 After-tax 2003 ------------------------------------------------------------------------------------------------------------- Asset impairments: Enterprises: Loy Yang (a) $ 125 $ 81 $ - $ - International Energy Distribution (b) - - 63 47 Other (c) - - 7 4 ------------------------------------------------------------------------------------------------------------- Total asset impairments $ 125 $ 81 $ 70 $ 51 =============================================================================================================
(a) 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. (b) In September 2003, we wrote down our investment in CMS Electric and Gas' Venezuelan electric distribution utility to reflect fair value. The impairment was based on estimates of the utility's future cash flows, incorporating certain assumptions about Venezuela's regulatory, political, and economic environment. (c) Primarily represents an impairment recorded to reflect the fair value of two generators. RESTRUCTURING AND OTHER COSTS In June 2002, we announced a series of initiatives to reduce our annual operating costs. The following tables show the amount charged to expense for restructuring costs, the payments made, and the unpaid balance of accrued costs for the nine months ended September 30, 2004 and September 30, 2003:
In Millions ------------------------------------------------------------------------------------------------------------- Involuntary Lease Termination Termination Total ------------------------------------------------------------------------------------------------------------- Beginning accrual balance, January 1, 2004 $ 3 $ 6 $ 9 Expense - - - Payments (1) (3) (4) ---------------------------------------- Ending accrual balance at September 30, 2004 $ 2 $ 3 $ 5 =============================================================================================================
In Millions ------------------------------------------------------------------------------------------------------------- Involuntary Lease Termination Termination Total ------------------------------------------------------------------------------------------------------------- Beginning accrual balance, January 1, 2003 $ 12 $ 8 $ 20 Expense 4 - 4 Payments (11) (1) (12) ---------------------------------------- Ending accrual balance at September 30, 2003 $ 5 $ 7 $ 12 =============================================================================================================
CMS-58 CMS Energy Corporation 3: UNCERTAINTIES Several business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we reasonably expect could have, a material impact on net sales, revenues, or income from continuing operations. Such trends and uncertainties are discussed in detail below. SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading transactions by CMS MST, CMS Energy's Board of Directors established a Special Committee to investigate matters surrounding the transactions and retained outside counsel to assist in the investigation. The Special Committee completed its investigation and reported its findings to the Board of Directors in October 2002. The Special Committee concluded, based on an extensive investigation, that the round-trip trades were undertaken to raise CMS MST's profile as an energy marketer with the goal of enhancing its ability to promote its services to new customers. The Special Committee found no effort to manipulate the price of CMS Energy Common Stock or affect energy prices. The Special Committee also made recommendations designed to prevent any recurrence of this practice. Previously, CMS Energy terminated its speculative trading business and revised its risk management policy. The Board of Directors adopted, and CMS Energy has implemented, the recommendations of the Special Committee. CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading. 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. SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of securities class action complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates. The complaints were filed as purported class actions in the United States District Court for the Eastern District of Michigan by shareholders who allege that they purchased CMS Energy's securities during a purported class period. The cases were consolidated into a single lawsuit and an amended and consolidated class action complaint was filed on May 1, 2003. The consolidated complaint contains a purported class period beginning on May 1, 2000 and running through March 31, 2003. It 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. The judge issued an opinion and order dated March 31, 2004 in connection with various pending motions, including plaintiffs' motion to amend the complaint and the motions to dismiss the complaint filed by CMS Energy, Consumers, and other defendants. The judge directed plaintiffs to file an amended complaint under seal and ordered an expedited hearing on the motion to amend, which was held on May 12, 2004. At the hearing, the judge ordered plaintiffs to file a Second Amended Consolidated Class Action complaint deleting Counts III and IV relating to purchasers of CMS PEPS, which the judge ordered dismissed with prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS Energy, Consumers, and the individual defendants filed new motions to dismiss on June 21, 2004. A hearing on those motions occurred on August 2, 2004 and the judge has taken the matter under advisement. CMS Energy, Consumers, and the individual defendants will defend themselves vigorously but cannot predict the outcome of this litigation. DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS: In May 2002, the Board of Directors of CMS Energy received a demand, on behalf of a shareholder of CMS Energy Common Stock, that it commence CMS-59 CMS Energy Corporation civil actions (i) to remedy alleged breaches of fiduciary duties by certain CMS Energy officers and directors in connection with round-trip trading by CMS MST, and (ii) to recover damages sustained by CMS Energy as a result of alleged insider trades alleged to have been made by certain current and former officers of CMS Energy and its subsidiaries. In December 2002, two new directors were appointed to the Board. The Board formed a special litigation committee in January 2003 to determine whether it is in CMS Energy's best interest to bring the action demanded by the shareholder. The disinterested members of the Board appointed the two new directors to serve on the special litigation committee. In December 2003, during the continuing review by the special litigation committee, CMS Energy was served with a derivative complaint filed on behalf of the shareholder in the Circuit Court of Jackson County, Michigan in furtherance of his demands. The date for CMS Energy and other defendants to answer or otherwise respond to the complaint has been extended to December 1, 2004, subject to such further extensions as may be mutually agreed upon by the parties and authorized by the Court. CMS Energy cannot predict the outcome of this matter. ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST, and certain named and unnamed officers and directors, in two lawsuits brought as purported class actions on behalf of participants and beneficiaries of the CMS Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July 2002 in United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended consolidated complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge issued an opinion and order dated March 31, 2004 in connection with the motions to dismiss filed by CMS Energy, Consumers, and the individuals. The judge dismissed certain of the amended counts in the plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims in the complaint. CMS Energy, Consumers, and the individual defendants filed answers to the amended complaint on May 14, 2004. A trial date has not been set, but is expected to be no earlier than late in 2005. CMS Energy and Consumers will defend themselves vigorously but cannot predict the outcome of this litigation. 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, this investigation will have on its business. GAS INDEX PRICE REPORTING LITIGATION: In August 2003, Cornerstone Propane Partners, L.P. (Cornerstone) filed a putative class action complaint in the United States District Court for the Southern District of New York against CMS Energy and dozens of other energy companies. The court ordered the Cornerstone complaint to be consolidated with similar complaints filed by Dominick Viola and Roberto Calle Gracey. The plaintiffs filed a consolidated complaint on January 20, 2004. The consolidated complaint alleges that false natural gas price reporting by the defendants manipulated the prices of NYMEX natural gas futures and options. The complaint contains two counts under the Commodity Exchange Act, one for manipulation and one for aiding and abetting violations. CMS Energy is no longer a defendant, however, CMS MST and CMS Field Services are named as defendants. (CMS Energy sold CMS Field Services to Cantera Natural Gas, Inc. but is required to indemnify Cantera Natural Gas, Inc. with respect to this action.) CMS-60 CMS Energy Corporation In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a putative class action lawsuit in the United States District Court for the Eastern District of California against a number of energy companies engaged in the sale of natural gas in the United States. CMS Energy is named as a defendant. The complaint alleges defendants entered into a price-fixing conspiracy by engaging in activities to manipulate the price of natural gas in California. The complaint contains counts alleging violations of the Sherman Act, Cartwright Act (a California statute), and the California Business and Profession Code relating to unlawful, unfair, and deceptive business practices. There is currently pending in the Nevada federal district court a multi district court litigation (MDL) matter involving 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 Sherman Act claim and some of the defendants in the MDL matter are also defendants in the Texas-Ohio case. Those defendants successfully argued to have the Texas-Ohio case transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case agreed to extend the time for all defendants to answer or otherwise respond until May 28, 2004 and on that date a number of defendants filed motions to dismiss. In order to negotiate possible dismissal and/or substitution of defendants, CMS Energy and two other parent holding company defendants were given further extensions to answer or otherwise respond to the complaint until November 16, 2004. Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint containing allegations similar to those made in the Texas-Ohio case, albeit limited to California state law claims, was filed in California state court in February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed a notice to remove this action to California federal district court, which was granted, and had it transferred to the MDL proceeding in Nevada. However, the plaintiff is seeking to have the case remanded back to California and until the issue is resolved, no further action will be taken. Another putative class action lawsuit, Fairhaven Power Company v. Encana Power Corporation, containing allegations similar to those made in the Texas-Ohio case, was filed in California federal court in September 2004. CMS Energy, Enterprises, and CMS MST are named as defendants. Three new, virtually identical actions were filed in San Diego Superior Court in July 2004, one by the County of Santa Clara, one by the County of San Diego and one by the City of and County of San Francisco and the San Francisco City Attorney (collectively the Municipal Lawsuits). Defendants, consisting of a number of energy companies including CMS Energy, CMS MST, Cantera Natural Gas, and Cantera Gas Company, are alleged to have engaged in false reporting of natural gas price and volume information and sham sales to artificially inflate natural gas retail prices in California. All three complaints allege claims for unjust enrichment and violations of the Cartwright Act, and the San Francisco action also alleges a claim for violation of the California Business and Profession Code relating to unlawful, unfair, and deceptive business practices. The Municipal Lawsuits were removed to federal district court, and conditional transfer orders were issued transferring the cases to the Nevada MDL proceeding. Plaintiffs in each of the Municipal Lawsuits intend to seek to have the cases remanded back to San Diego Superior Court, and they have agreed to extend the time to answer or otherwise respond to the complaints to thirty days from the date an order on the motion to remand is issued. Two new lawsuits were filed in California, one a putative class action in San Diego Superior Court on behalf of retail consumers of natural gas, and one in Alameda Superior Court on behalf of a cooperative of public agencies engaged in the retail purchase of natural gas. The actions are virtually identical to the Municipal Lawsuits, and the defendants include CMS Energy, CMS MST, Cantera Natural Gas, and Cantera Gas Company. More of such "copycat" actions may follow. CMS Energy and the other CMS defendants will defend themselves vigorously, but cannot predict the outcome of these matters. CMS-61 CMS Energy Corporation CONSUMERS' UNCERTAINTIES Several business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric and gas operations. Such trends and uncertainties include: Environmental - increased capital expenditures and operating expenses for Clean Air Act compliance, and - potential environmental liabilities arising from various environmental laws and regulations, including potential liability or expense relating to the Michigan Natural Resources and Environmental Protection Acts, Superfund, and at former manufactured gas plant facilities. Restructuring - response of the MPSC and Michigan legislature to electric industry restructuring issues, - ability to meet peak electric demand requirements at a reasonable cost, without market disruption, - ability to recover any of our net Stranded Costs under the regulatory policies set by the MPSC, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer, instead of an electric transmission owner and the impact of the evolving RTO infrastructure. Regulatory - recovery of nuclear decommissioning costs, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, - regulatory decisions concerning the RCP, - inadequate regulatory response to applications for requested rate increases, - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, and - proposed distribution integrity rules and mandates. Other - pending litigation regarding PURPA qualifying facilities, - transmission pipeline integrity mandates, maintenance and remediation costs, and - other pending litigation. 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. Clean Air: The EPA and the state regulations require us to make significant capital expenditures estimated to be $802 million. As of September 30, 2004, we have incurred $500 million in capital expenditures to comply with the EPA regulations and anticipate that the remaining $302 million of capital expenditures will be made between 2004 and 2011. These expenditures include installing catalytic reduction technology at some of our coal-fired electric plants. Based on the Customer Choice Act, beginning January 2004, an annual return of and on these types of capital expenditures, to the extent CMS-62 CMS Energy Corporation they are above depreciation levels, is expected to be recoverable from customers, subject to the MPSC prudency hearing. The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits 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 plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions allowances for years 2004 through 2009. The cost of the allowances is estimated to average $7 million per year for 2004-2006; the cost will decrease after year 2006 with the installation of plant control technology. The cost of the allowances is accounted for as inventory. The allowance inventory is expensed as the coal-fired electric plants generate electricity. The price for nitrogen oxide emissions allowances is volatile and could change substantially. The EPA has proposed a Clean Air Interstate Rule that would require additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. If implemented, this rule would potentially require expenditures equivalent to those efforts in progress to reduce nitrogen oxide emissions as required under the Title I provisions of the Clean Air Act. The rule proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent and nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two alternative sets of rules to reduce emissions of mercury and nickel from coal-fired and oil-fired electric plants. Until the proposed environmental rules are finalized, an accurate cost of compliance cannot be determined. Our switch to western coal as fuel has resulted in reduced plant emissions, lower operating costs, and flexibility in meeting future regulatory compliance requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide allowances optimizes our overall cost of regulatory compliance by delaying capital expenditures and minimizing regulatory uncertainty. Western coal has reduced our overall cost of fuel and reduced the impact on us from the recent increases in eastern coal prices. Several bills have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that greenhouse gas emission reduction rules come into effect, such mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sectors. We cannot estimate the potential effect of United States federal or state level greenhouse gas policy on future consolidated results of operations, cash flows, or financial position due to the speculative nature of the policy. We stay abreast of and engage in the greenhouse gas policy developments, and will continue to assess and respond to their potential implications on our business operations. Water: In March 2004, the EPA changed the rules that govern generating plant cooling water intake systems. The new rules require significant reduction in fish killed by operating equipment. Some of our facilities will be required to comply by 2006. We are studying the rules to determine the most cost-effective solutions for compliance. CMS-63 CMS Energy Corporation 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 past experience, we estimate that our share of the total liability for the known Superfund sites will be between $1 million and $9 million. As of September 30, 2004, we have recorded a liability for the minimum amount of our estimated Superfund liability. In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at the Ludington Pumped Storage facility. We removed and replaced part of the PCB material. We have proposed a plan to deal with the remaining materials and are awaiting a response from the EPA. LITIGATION: In October 2003, a group of eight PURPA qualifying facilities selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit alleges that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. More specifically, the lawsuit alleges that we should be basing the energy charge calculation on the cost of more expensive eastern coal, rather than on the cost of the coal actually burned by us for use in our coal-fired generating plants. We believe we have been performing the calculation in the manner prescribed by the power purchase agreements, and have filed a request with the MPSC (as a supplement to the 2004 PSCR plan case) that asks the MPSC to review this issue and to confirm that our method of performing the calculation is correct. We filed a motion to dismiss the lawsuit in the Ingham County Circuit Court due to the pending request at the MPSC concerning the PSCR plan case. In February 2004, the judge ruled on the motion and deferred to the primary jurisdiction of the MPSC. This ruling resulted in a dismissal of the circuit court case without prejudice. In October 2004, the ALJ in the PSCR plan case issued a Proposal for Decision concluding that we have been correctly administering the energy charge calculation methodology that is specified in the power purchase agreements. Although only eight qualifying facilities have raised the issue, the same energy charge methodology is used in the PPA with the MCV Partnership and in approximately 20 additional power purchase agreements with us, representing a total of 1,670 MW of electric capacity. The eight plaintiff qualifying facilities have appealed the dismissal of the circuit court case to the Michigan Court of Appeals. We cannot predict the outcome of this matter. CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, the Michigan legislature passed electric utility restructuring legislation known as the Customer Choice Act. This Act: - allows all customers to choose their electric generation supplier effective January 1, 2002, - provides for a one-time five percent residential electric rate reduction, - froze all electric rates through December 31, 2003, and established a rate cap for residential customers through at least December 31, 2005, and a rate cap for small commercial and industrial customers through at least December 31, 2004, - allows deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and during the rate freeze-cap period, including the cost of money, CMS-64 CMS Energy Corporation - allows for the use of Securitization bonds to refinance qualified costs, - allows recovery of net Stranded Costs and implementation costs incurred as a result of the passage of the Act, - requires Michigan utilities to join a FERC-approved RTO or sell their interest in transmission facilities to an independent transmission owner, - requires Consumers, Detroit Edison, and AEP to expand jointly their available transmission capability by at least 2,000 MW, and - establishes a market power supply test that, if not met, may require transferring control of generation resources in excess of that required to serve retail sales requirements. The following summarizes our status under the last three provisions of the Customer Choice Act. First, we chose to sell our interest in our transmission facilities to an independent transmission owner to comply with the Customer Choice Act. For additional details regarding the sale of the transmission facility, see "Transmission Sale" within this Note. Second, in July 2002, the MPSC issued an order approving our plan to achieve the increased transmission capacity required under the Customer Choice Act. We have completed the transmission capacity projects identified in the plan and have submitted verification of this fact to the MPSC. We believe we are in full compliance. Lastly, in September 2003, the MPSC issued an order finding that we are in compliance with the market power supply test set forth in the Customer Choice Act. ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms, and conditions under which retail customers are permitted to choose an electric supplier. These revised tariffs allow ROA customers, upon as little as 30 days notice to us, to return to our generation service at current tariff rates. If any class of customers' (residential, commercial, or industrial) ROA load reaches ten percent of our total load for that class of customers, then returning ROA customers for that class must give 60 days notice to return to our generation service at current tariff rates. However, we may not have capacity available to serve returning ROA customers that is sufficient or reasonably priced. As a result, we may be forced to purchase electricity on the spot market at higher prices than we can recover from our customers during the rate cap periods. We cannot predict the total amount of electric supply load that may be lost to alternative electric suppliers. As of October 2004, alternative electric suppliers are providing 877 MW of load. This amount represents 11 percent of the total distribution load and an increase of 45 percent compared to October 2003. ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric restructuring proceedings. They are: - Securitization, - Stranded Costs, - implementation costs, - security costs, - Section 10d(4) Regulatory Assets, and - transmission rates. CMS-65 CMS Energy Corporation The following chart summarizes our filings with the MPSC. For additional details related to these proceedings, see the related sections within this Note.
Year(s) Years Requested Proceeding Filed Covered Amount Status ----------------------------------------------------------------------------------------------------------------------------- Securitization 2003 N/A $1.083 billion MPSC denied our request to issue additional Securitization bonds. Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced zero Stranded Costs for 2000 through 2001, which we are appealing. Filings for 2002 and 2003 in the amount of $116 million are pending MPSC approval. Implementation 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the years Costs 1997-2001, plus $20 million for the cost of money through 2003. Implementation cost filings for 2002 and 2003 in the amount of $8 million, which includes the cost of money through 2003, are still pending MPSC approval. Security Costs 2004 2001-2005 $25 million MPSC approved the $25 million requested for recovery. As of September 30, 2004, we have recorded $21 million of costs incurred as a regulatory asset. Section 10d(4) 2004 2001-2005 $628 million Filed with the MPSC in October 2004. Regulatory Assets =============================================================================================================================
(a) Amount includes the cost of money through the year in which we expected to receive recovery from the MPSC and assumes recovery of Clean Air Act costs through the Section 10d(4) Regulatory Asset case. If Clean Air Act costs are not recovered through the Section 10d(4) Regulatory Asset case, Stranded Costs requested would total $304 million. (b) Amount includes the cost of money through the year prior to the year filed. Securitization: The Customer Choice Act allows for the use of Securitization bonds to refinance certain qualified costs. Since Securitization involves issuing bonds secured by a revenue stream from rates collected directly from customers to service the bonds, Securitization bonds typically have a higher credit rating than conventional utility corporate financing. In 2000 and 2001, the MPSC issued orders authorizing us to issue Securitization bonds. We issued our first Securitization bonds in late 2001. Securitization resulted in: - lower interest costs, and - longer amortization periods for the securitized assets. CMS-66 CMS Energy Corporation We will recover the repayment of principal, interest, and other expenses relating to the bond issuance through a Securitization charge and a tax charge that began in December 2001. These charges are subject to an annual true up until one year before the last scheduled bond maturity date, and no more than quarterly thereafter. The December 2004 true up filed with the MPSC in October 2004, is expected to modify the total Securitization and related tax charges from 1.718 mills per kWh to 1.735 mills per kWh. There will be no impact on customer bills from Securitization for most of our electric customers until the Customer Choice Act rate cap period expires, and an electric rate case is processed. Securitization charge collections, $38 million for the nine months ended September 30, 2004, and $37 million for the nine months ended September 30, 2003, are remitted to a trustee. Securitization charge collections are restricted to the repayment of the principal and interest on the Securitization bonds and payment of the ongoing expenses of Consumers Funding. Consumers Funding is legally separate from Consumers. The assets and income of Consumers Funding, including the securitized property, are not available to creditors of Consumers or CMS Energy. In March 2003, we filed an application with the MPSC seeking approval to issue additional Securitization bonds. In June 2003, the MPSC issued a financing order authorizing the issuance of Securitization bonds in the amount of $554 million. We filed for rehearing and clarification on a number of features in the financing order. In October 2004, the MPSC issued an order that reversed the June 2003 financing order and denied our request to issue additional Securitization bonds. Clean Air Act costs, originally included in our Stranded Cost filings, were also part of this Securitization request that was denied. The MPSC order, however, also gave us the option to file for recovery of these costs through a Section 10d(4) Regulatory Asset case, which we filed in October 2004. Stranded Costs: The Customer Choice Act allows electric utilities to recover their net Stranded Costs, without defining the term. In December 2001, the MPSC Staff recommended a methodology, which calculated net Stranded Costs as the shortfall between: - the revenue required to cover the costs associated with fixed generation assets and capacity payments associated with purchase power agreements, and - the revenues received from customers under existing rates available to cover the revenue requirement. The MPSC authorizes us to use deferred accounting to recognize the future recovery of costs determined to be stranded. According to the MPSC, net Stranded Costs are to be recovered from ROA customers through a Stranded Cost recovery charge. However, the MPSC has not yet approved such a charge. The MPSC has declined to resolve numerous issues regarding the net Stranded Cost recovery methodology in a way that would allow a reliable prediction of the level of Stranded Costs. As a result, we have not recorded regulatory assets to recognize the future recovery of such costs. CMS-67 CMS Energy Corporation The following table outlines our applications filed with the MPSC and the status of recovery for these costs:
In Millions ----------------------------------------------------------------------------------------------------------------- Requested, without recovery of Requested, with recovery of Clean Air Act costs through the Clean Air Act costs through the MPSC approval of Section 10d(4) approval of Section 10d(4) ordered Year Year Regulatory Assets, including Regulatory Assets, recoverable Filed Incurred cost of money including cost of money amount ----------------------------------------------------------------------------------------------------------------- 2002 2000 $ 26 $12 $ - 2002 2001 46 9 - 2003 2002 104 47 Pending 2004 2003 128 69 Pending =================================================================================================================
We are currently in the process of appealing the MPSC orders regarding Stranded Costs for 2000 and 2001 with the Michigan Court of Appeals and the Michigan Supreme Court. In June 2004, the MPSC conducted hearings for our 2002 Stranded Cost application. In July 2004, the ALJ issued a Proposal for Decision in our 2002 net Stranded Cost case, which recommended that the MPSC find that we incurred net Stranded Costs of $12 million. This recommendation includes the cost of money through July 2004 and excludes Clean Air Act costs. Hearings for our 2003 Stranded Cost application were conducted in August 2004. The MPSC Staff issued a position on our 2003 net Stranded Cost application, which resulted in a Stranded Cost calculation of $52 million. This amount includes the cost of money, but excludes Clean Air Act costs. We cannot predict how the MPSC will rule on our requests for recoverability of 2002 and 2003 Stranded Costs or whether the MPSC will adopt a Stranded Cost recovery method that will offset fully any associated margin loss from ROA. Implementation Costs: The Customer Choice Act allows electric utilities to recover their implementation costs. The following table outlines our applications filed with the MPSC and the status of recovery for these costs:
In Millions ----------------------------------------------------------------------------------------------------------------- Recoverable, including (b) cost of money through Year Filed Year Incurred Requested Disallowed Allowed 2003 ----------------------------------------------------------------------------------------------------------------- 1999 1997 & 1998 $ 20 $ 5 $ 15 $22 2000 1999 30 5 25 33 2001 2000 25 5 20 24 2002 2001 8 - 8 9 2003 & 2004 (a) 2002 7 Pending Pending Pending 2004 2003 1 Pending Pending Pending =================================================================================================================
(a) On March 31, 2004, we requested additional 2002 implementation cost recovery of $5 million related to our former participation in the development of the Alliance RTO. This cost has been expensed; therefore, the amount is not included as a regulatory asset. CMS-68 CMS Energy Corporation (b) Amounts include the cost of money through the year prior to the year filed. In addition to seeking MPSC approval for these costs, we are pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million for implementation costs related to our former participation in the development of the Alliance RTO. Included in this amount is $5 million pending approval by the MPSC as part of 2002 implementation costs application. The FERC has denied our request for reimbursement and we are appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. We cannot predict the outcome of the appeal process or the amount, if any, we will collect for Alliance RTO development costs. The MPSC disallowed certain costs, determining that these amounts did not represent costs incremental to costs already reflected in electric rates. As of September 30, 2004, we incurred and deferred as a regulatory asset $92 million of implementation costs, which includes $25 million associated with the cost of money. We believe the implementation costs and associated cost of money are fully recoverable in accordance with the Customer Choice Act. In June 2004, following an appeal and remand of initial MPSC orders relating to 1999 implementation costs, the MPSC authorized the recovery of all previously approved implementation costs for the years 1997 through 2001 totaling $88 million. This total includes the cost of money through 2003. Additional carrying costs will be added until collection occurs. The implementation costs will be recovered through surcharges over 36-month collection periods and phased in as applicable rate caps expire. In September 2004, the ALJ issued a Proposal for Decision recommending full recovery of the requested 2002 and 2003 implementation costs. We cannot predict the amount, if any, the MPSC will approve as recoverable costs for these years. Security Costs: The Customer Choice Act, as amended, allows for recovery of new and enhanced security costs as a result of federal and state regulatory security requirements incurred before January 1, 2006. In August 2004, the MPSC approved a settlement agreement that authorizes full recovery of $25 million in requested security costs over a five-year period beginning in September 2004. The amount includes reasonable and prudent security enhancements through December 31, 2005. All retail customers, except customers of alternative electric suppliers, will pay these charges. As a result, in August 2004, we recorded total approved security costs incurred to date, including the cost of money. As of September 30, 2004, we have recorded $21 million in security costs as a regulatory asset. The following table outlines our application filed with the MPSC and the status of recovery for these costs:
In Millions ---------------------------------------------------------------------------------------- Regulatory asset as of Year Filed Years Covered Requested September 30, 2004 Allowed ---------------------------------------------------------------------------------------- 2004 2001-2005 $ 25 $21 $25 ========================================================================================
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze-cap periods, including the cost of money. The section also allows deferred recovery of expenses incurred during the rate freeze-cap periods that result from changes in taxes, laws or other state or federal governmental actions. In October 2004, we filed an application with the MPSC seeking recovery of $628 million in costs from 2000 through 2005 under section 10d(4). The request includes capital expenditures in excess of depreciation, Clean Air Act costs, and other expenses related to changes in law or governmental action incurred during the rate freeze-cap period. Of the $628 million, $152 million CMS-69 CMS Energy Corporation relates to the cost of money. Also included in this application is $74 million of costs that were also incorporated in our Stranded Costs filings. We cannot predict the amount, if any, the MPSC will approve as recoverable. The following table outlines our application filed with the MPSC and the status of recovery for these costs:
In Millions ----------------------------------------------------------------------------------- Year Filed Years Covered Requested Allowed ----------------------------------------------------------------------------------- 2004 2000-2005 $628 Pending ===================================================================================
Transmission Rates: Our application of JOATT transmission rates to customers during past periods is under FERC review. The rates included in these tariffs were applied to certain transmission transactions affecting both Detroit Edison's and our transmission systems between 1997 and 2002. We believe our reserve is sufficient to satisfy our refund obligation to any of our former transmission customers under our former JOATT. TRANSMISSION SALE: In May 2002, we sold our electric transmission system to MTH, a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc. We are currently in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized of approximately $2 million to $3 million. Under an agreement with MTH, our transmission rates are fixed by contract at current levels through December 31, 2005, and are subject to FERC ratemaking thereafter. However, we are subject to certain additional MISO surcharges, which we estimate to be $10 million in 2004. CONSUMERS' ELECTRIC UTILITY RATE MATTERS PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The standards relate to restoration after outages, safety, and customer services. The MPSC order calls for financial penalties in the form of customer credits if the standards for the duration and frequency of outages are not met. We met or exceeded all approved standards for year-end results for both 2002 and 2003. As of September 2004, we are in compliance with the acceptable level of performance. We are a member of an industry coalition that has appealed the customer credit portion of the performance standards to the Michigan Court of Appeals. We cannot predict the likely effects of the financial penalties, if any, nor can we predict the outcome of the appeal. Likewise, we cannot predict our ability to meet the standards in the future or the cost of future compliance. POWER SUPPLY COSTS: We were required to provide backup service to ROA customers on a best efforts basis. In October 2003, we provided notice to the MPSC that we would terminate the provision of backup service in accordance with the Customer Choice Act, effective January 1, 2004. To reduce the risk of high electric prices during peak demand periods and to achieve our reserve margin target, we employ a strategy of purchasing 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. As we did in 2004, we are currently planning for a reserve margin of approximately 11 percent for summer 2005, or supply resources equal to 111 percent of projected summer peak load. Of the 2005 supply resources target of 111 percent, approximately 101 percent is expected to be met from owned electric generating plants and long-term power purchase contracts, and approximately 10 percent from short-term contracts, options for physical deliveries, and other agreements. As of September 30, 2004, we have purchased CMS-70 CMS Energy Corporation capacity and energy contracts partially covering the estimated reserve margin requirements for 2004 through 2007. As a result, we have recognized an asset of $13 million for unexpired capacity and energy contracts. As of October 2004, the total premium costs of electric capacity and energy contracts for 2004 is expected to be approximately $12 million. PSCR: As a result of meeting the transmission capability expansion requirements and the market power test, as discussed within this Note, we have met the requirements under the Customer Choice Act to return to the PSCR process. The PSCR process provides for the reconciliation of actual power supply costs with power supply revenues. This process assures recovery of all reasonable and prudent power supply costs actually incurred by us. In September 2003, we submitted a PSCR filing to the MPSC that reinstates the PSCR process for customers whose rates are no longer frozen or capped as of January 1, 2004. The proposed PSCR charge allows us to recover a portion of our increased power supply costs from large commercial and industrial customers and, subject to the overall rate caps, from other customers. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. In October 2004, the ALJ issued a Proposal for Decision, which recommended approval of our 2004 PSCR factor, with minor adjustments. The PSCR factor recommended for approval includes nitrogen oxide emissions allowance costs and requested transmission costs, less a minor adjustment. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $32 million in 2004. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from all other customers. Unless we receive an order from the MPSC, we expect to self-implement this proposed 2005 PSCR charge in January 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings. OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990 and to supply electricity and steam to Dow. We hold, through two wholly owned subsidiaries, the following assets related to the MCV Partnership and the MCV Facility: - CMS Midland owns a 49 percent general partnership interest in the MCV Partnership, and - CMS Holdings holds, through the FMLP, a 35 percent lessor interest in the MCV Facility. In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 11, Implementation of New Accounting Standards. Our consolidated retained earnings include undistributed earnings from the MCV Partnership of $244 million at September 30, 2004 and $238 million at September 30, 2003. Power Supply Purchases from the MCV Partnership: Our annual obligation to purchase capacity from the MCV Partnership is 1,240 MW through the term of the PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's availability, a levelized average capacity charge of 3.77 cents per kWh, CMS-71 CMS Energy Corporation and a fixed energy charge. We also pay a variable energy charge based on our average cost of coal consumed for all kWh delivered. Effective January 1999, we reached a settlement agreement with the MCV Partnership that capped capacity payments made on the basis of availability that may be billed by the MCV Partnership at a maximum 98.5 percent availability level. Since January 1993, the MPSC has permitted us to recover capacity charges averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges. Since January 1996, the MPSC has also permitted us to recover capacity charges for the remaining 325 MW of contract capacity with an initial average charge of 2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by 2004 and thereafter. However, due to the frozen retail rates required by the Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions of the PPA are subject to certain limitations discussed below. In 1992, we recognized a loss and established a liability for the present value of the estimated future underrecoveries of power supply costs under the PPA based on the MPSC cost recovery orders. We estimate that 51 percent of the actual cash underrecoveries for 2004 will be charged to the PPA liability, with the remaining portion charged to operating expense as a result of our 49 percent ownership in the MCV Partnership. The remaining liability associated with the loss totaled $6 million at September 30, 2004. We will expense all cash underrecoveries directly to income once the PPA liability is depleted. We expect the PPA liability to be depleted in late 2004. If the MCV Facility's generating availability remains at the maximum 98.5 percent level, our cash underrecoveries associated with the PPA could be as follows:
In Millions ------------------------------------------------------------------------------- 2004 2005 2006 2007 ------------------------------------------------------------------------------- Estimated cash underrecoveries at 98.5% $56 $56 $55 $39 Amount to be charged to operating expense 29 56 55 39 Amount to be charged to PPA liability 27 - - - ===============================================================================
Beginning January 1, 2004, the rate freeze for large industrial customers was no longer in effect and we returned to the PSCR process. Under the PSCR process, we will recover from our customers the approved capacity and fixed energy charges based on availability, up to an availability cap of 88.7 percent as established in previous MPSC orders. Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility: As a result of returning to the PSCR process on January 1, 2004, we returned to dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in order to maximize recovery from electric customers of our capacity and fixed energy payments. This fixed load dispatch increases the MCV Facility's output and electricity production costs, such as natural gas. As the spread between the MCV Facility's variable electricity production costs and its energy payment revenue widens, the MCV Partnership's financial performance and our investment in the MCV Partnership is and will be impacted negatively. Under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased CMS-72 CMS Energy Corporation substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. Until September 2007, the PPA and settlement agreement require us to pay capacity and fixed energy charges based on the MCV Facility's actual availability up to the 98.5 percent cap. After September 2007, we expect to claim relief under the regulatory out provision in the PPA, limiting our capacity and fixed energy payments to the MCV Partnership to the amount collected from our customers. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 2007 may affect negatively the earnings of the MCV Partnership and the value of our investment in the MCV Partnership. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. Resource Conservation Plan: In February 2004, we filed the RCP with the MPSC that is intended to help conserve natural gas and thereby improve our investment in the MCV Partnership. This plan seeks approval to: - dispatch the MCV Facility based on natural gas market prices without increased costs to electric customers, - give Consumers a priority right to buy excess natural gas as a result of the reduced dispatch of the MCV Facility, and - fund $5 million annually for renewable energy sources such as wind power projects. The RCP will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit Consumers' ownership interest in the MCV Partnership. The amount of PPA capacity and fixed energy payments recovered from retail electric customers would remain capped at 88.7 percent. Therefore, customers will not be charged for any increased power supply costs, if they occur. Consumers and the MCV Partnership have reached an agreement that the MCV Partnership will reimburse Consumers for any incremental power costs incurred to replace the reduction in power dispatched from the MCV Facility. In August 2004, several qualifying facilities sought and obtained a stay of the RCP proceeding from the Ingham County Circuit Court after their previous attempt to intervene in the proceeding was denied by the MPSC. In an attempt to resolve this intervention issue as quickly as possible, the MPSC issued an order permitting the qualifying facilities to participate as intervenors. As a result, the Ingham County Circuit Court stay was lifted and hearings were completed in October 2004. The MPSC has decided to dispense with a Proposal for Decision from the presiding ALJ and will issue a decision directly. We cannot predict if or when the MPSC will approve the RCP. The two most significant variables in the analysis of the MCV Partnership's future financial performance are the forward price of natural gas for the next 20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of capacity and fixed energy payments. Historically, natural gas prices have been volatile. Presently, there is no consensus in the marketplace on the price or range of future prices of natural gas. Even with an approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment of our investment in the MCV Partnership. We presently cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our investment in the MCV Partnership. MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of CMS-73 CMS Energy Corporation approximately $35 million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund (net of approximately $16 million of deferred expenses) has not been recognized in year-to-date 2004 earnings. NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates for Big Rock and Palisades assume that each plant site will eventually be restored to conform to the adjacent landscape and all contaminated equipment will be disassembled and disposed of in a licensed burial facility. 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 each plant on March 31, 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. Since Big Rock is currently in the process of being decommissioned, the estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. The Palisades cost estimate assumes the plant will be safely stored and subsequently decommissioned. In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding the decommissioning trust funds for both sites. In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. The MPSC order set the annual decommissioning surcharge for Palisades at $6 million through 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability. However, based on current projections, the current level of funds provided by the trusts is not adequate to fully fund the decommissioning of Big Rock or Palisades. This is due in part to the DOE's failure to accept the spent nuclear fuel and lower returns on the trust funds. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation, as discussed below in "Nuclear Matters" within this Note. We will also seek additional relief from the MPSC. In the case of Big Rock, excluding the additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we are currently projecting that the level of funds provided by the trust will fall short of the amount needed to complete the decommissioning by $26 million. At this point in time, we plan to provide the additional amounts needed from our corporate funds and, subsequent to the completion of radiological decommissioning work, seek recovery of such expenditures at the MPSC. We cannot predict how the MPSC will rule on our request. In the case of Palisades, excluding additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we have concluded that the existing surcharge needs to be increased to $25 million annually, beginning January 1, 2006, and continue through 2011, our current license expiration date. In June 2004, we filed an application with the MPSC seeking approval to increase the surcharge for recovery of decommissioning costs related to Palisades beginning in 2006. In September 2004, we announced that we will seek a 20-year license renewal for Palisades. We cannot predict what effect the application and announcement may have on the MPSC request. NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor vessel, steam drum, and radioactive waste processing systems in 2003, dismantlement of plant systems is nearly complete and demolition of the remaining plant structures is set to begin. The restoration project is on schedule to CMS-74 CMS Energy Corporation return approximately 530 acres of the site, including the area formerly occupied by the nuclear plant, to a natural setting for unrestricted use in mid-2006. An additional 30 acres, the area where seven transportable dry casks loaded with spent nuclear fuel and an eighth cask loaded with high-level radioactive waste material are stored, will be returned to a natural state by the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010. The NRC and the MDEQ continue to find all decommissioning activities at Big Rock are being performed in accordance with applicable regulations including license requirements. Palisades: In August 2004, the NRC completed its mid-cycle plant performance assessment of Palisades. The assessment for Palisades covered the first half of 2004. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. As of September 2004, all inspection findings were classified as having very low safety significance and all performance indicators show performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through March 2006. Our Palisades plant is currently undergoing a regularly scheduled refueling outage. In conjunction with this scheduled outage, we have completed inspection of all 54 nuclear reactor vessel head penetrations. Small cracks were identified in the welds on two of the 45 control rod drive penetration nozzles. No external primary coolant system leakage or damage to the reactor head material was noted. Sections of the two penetrations have been removed and replaced. Post-weld testing, restoration of the support attachments, and reactor head installation on the vessel are in progress and are expected to be complete by mid-November. The total outage extension caused by the weld cracks will be approximately four weeks. The plant is expected to return to service by the end of November. We expect to have sufficient power at all times to meet our load requirements from our other plants or purchase arrangements. These replacement power requirements could increase the cost of power by an estimated $1.6 million (pretax) per week during an extended refueling outage. Of this estimated amount, approximately $0.6 million per week is not recoverable from our customers. The preliminary estimate of the cost of repair to the reactor vessel is $5 million. Our ability to make off-system sales may also be affected by an extension of the refueling outage. However, until all repairs are made, there can be no assurance of the length and effect of the outage on our operations and consolidated earnings. The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of September 30, 2004, we have loaded 22 dry casks with spent nuclear fuel. In September 2004, we announced that we will seek a license renewal for the Palisades plant. The plant's current license from the NRC expires in 2011. NMC, which operates the facility, will apply for a 20-year license renewal for the plant on behalf of Consumers. The Palisades renewal application is scheduled to be filed in the first quarter of 2005. 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. CMS-75 CMS Energy Corporation 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. In July 2004, the DOE filed an amended answer and motion to dismiss the complaint. In October 2004, we filed a response to the DOE's motion and our motion for summary judgment on liability. The motions are expected to be heard in late 2004 or early 2005. If our litigation against the DOE is successful, we anticipate future recoveries from the DOE. We plan to use recoveries to pay the cost of spent nuclear fuel storage until the DOE takes possession as required by law. We can make no assurance that the litigation against the DOE will be successful. In July 2002, Congress approved and the President signed a bill designating the site at Yucca Mountain, Nevada, for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE will submit, by December 2004, an application to the NRC for a license to begin construction of the repository. The application and review process is estimated to take several years. Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council, the Public Interest Research Group in Michigan, and the Michigan Consumer Federation filed a complaint with the MPSC, which was served on us by the MPSC in April 2003. The complaint asks the MPSC to initiate a generic investigation and contested case to review all facts and issues concerning costs associated with spent nuclear fuel storage and disposal. The complaint seeks a variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service Corporation. The complaint states that amounts collected from customers for spent nuclear fuel storage and disposal should be placed in an independent trust. The complaint also asks the MPSC to take additional actions. In May 2003, Consumers and other named utilities each filed motions to dismiss the complaint. We are unable to predict the outcome of this matter. 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 $27 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 hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. The United States Congress enacted the Price-Anderson Act to provide financial liability protection for those parties who may be liable for a nuclear accident or incident. Part of the Price-Anderson Act's financial protection is a mandatory industry-wide program where 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 $10 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. CMS-76 CMS Energy Corporation Big Rock remains insured for nuclear liability by a combination of insurance and a NRC indemnity totaling $544 million, and 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. COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional purchase obligations that represent normal business operating contracts. These contracts are used to assure an adequate supply of goods and services necessary for the operation of our business and to minimize exposure to market price fluctuations. We believe that these future costs are prudent and reasonably assured of recovery in future rates. Coal Supply and Transportation: We have entered into coal supply contracts with various suppliers and associated rail transportation contracts for our coal-fired generating stations. Under the terms of these agreements, we are obligated to take physical delivery of the coal and make payment based upon the contract terms. Our coal supply contracts expire through 2006, and total an estimated $154 million. Our coal transportation contracts expire through 2007, and total an estimated $92 million. Long-term coal supply contracts have accounted for approximately 60 to 90 percent of our annual coal requirements over the last 10 years. Although future contract coverage is not finalized at this time, we believe that it will be within the historic 60 to 90 percent range. Power Supply, Capacity, and Transmission: As of September 30, 2004, we had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2004 and 2005 totaling $6 million. We also had 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 2004 through 2030 total an estimated $3.004 billion, undiscounted. This amount may vary depending upon plant availability and fuel costs. If a plant were not available to deliver electricity to us, then we would not be obligated to make the capacity payment until the plant could deliver. CONSUMERS' GAS UTILITY CONTINGENCIES GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial 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. We have completed initial investigations at the 23 sites. We will continue to implement remediation plans for sites where we have received MDEQ remediation plan approval. We will also work toward resolving environmental issues at sites as studies are completed. We have estimated our costs for investigation and remedial action at all 23 sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost Model. We expect our remaining costs to be between $37 million and $90 million. The range reflects multiple alternatives with various assumptions for resolving the environmental issues at each site. The estimates are based on discounted 2003 costs using a discount rate of three percent. The discount rate represents a ten-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 insurance proceeds and through the MPSC approved rates charged to our customers. As of September 30, 2004, we have recorded a regulatory liability of $40 million, net of $41 million of CMS-77 CMS Energy Corporation expenditures incurred to date, and a regulatory asset of $65 million. 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. In its November 2002 gas distribution rate order, the MPSC authorized us to continue to recover approximately $1 million of manufactured gas plant facilities environmental clean-up costs annually. This amount will continue to be offset by $2 million to reflect amounts recovered from all other sources. We defer and amortize, over a period of 10 years, manufactured gas plant facilities environmental clean-up costs above the amount currently included in rates. Additional amortization of the expense in our rates cannot begin until after a prudency review in a gas rate case. CONSUMERS' GAS UTILITY RATE MATTERS GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers for our actual cost of purchased natural gas. The GCR process is designed to allow us to recover all of our prudently incurred gas costs. The MPSC reviews these costs for prudency in an annual reconciliation proceeding. The following table summarizes our GCR reconciliation filings with the MPSC. Additional details related to these proceedings follow the table. Gas Cost Recovery Reconciliation
------------------------------------------------------------------------------------------------------------------ Net Over GCR Year Date Filed Order Date Recovery Status ------------------------------------------------------------------------------------------------------------------ 2001-2002 June 2002 May 2004 $3 million $2 million has been refunded; $1 million is included in our 2003-2004 GCR reconciliation filing 2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest accrued through March 2003, and an $11 million disallowance settlement agreement 2003-2004 June 2004 Pending $28 million Filing includes the $1 million and $5 million GCR net overrecovery above ==================================================================================================================
Net overrecovery amounts included in the table above include refunds received by us from our suppliers and required by the MPSC to be refunded to our customers. GCR year 2001-2002: In June 2002, we filed a reconciliation of GCR costs and revenues for the 12-months ended March 2002. In May 2004, the MPSC issued an order directing us to refund a net overrecovery of $3 million, plus interest. Of this, $2 million has been refunded and the remaining $1 million is included in our 2003-2004 GCR year reconciliation filing. GCR year 2002-2003: In June 2003, we filed a reconciliation of GCR costs and revenues for the 12-months ended March 2003. We proposed to recover from our customers approximately $6 million of under recovered gas costs, including interest through March 2003, using a roll-in methodology. The roll-in methodology incorporates a GCR over/underrecovery in the next GCR plan year. The approach was approved by the MPSC in a November 2002 order. CMS-78 CMS Energy Corporation In January 2004, intervenors filed their positions in our 2002-2003 GCR reconciliation case. Their positions were that not all of our gas purchasing decisions were prudent from April 2002 through March 2003 and they proposed disallowances. In 2003, we reserved $11 million for a 2002-2003 GCR disallowance. Interest on this amount from April 2003 through February 2004, at our authorized rate of return, increased this amount by $1 million. The interest was recorded as an expense in 2003. In March 2004, the parties in the case reached a settlement agreement that resulted in a GCR disallowance of $11 million for the GCR period. The settlement agreement was approved by the MPSC in March 2004. The prior year $6 million underrecovery and $11 million disallowance are included in our 2003-2004 GCR year filing using the roll-in methodology. The roll-in methodology incorporates the GCR underrecovery in the next GCR plan year. The approach was approved by the MPSC in a November 2002 order. GCR year 2003-2004: In June 2004, we filed a reconciliation of GCR costs and revenues for the 12-months ended March 2004. We proposed to refund to our customers $28 million of overrecovered gas cost, plus interest. We proposed that the refund be included in the 2004-2005 GCR plan year. The overrecovery includes the $1 million refund for the 2001-2002 GCR reconciliation case, the $11 million refund settlement for the 2002-2003 GCR reconciliation case, as well as refunds received by us from our suppliers and required by the MPSC to be refunded to our customers. GCR plan for year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding. Recent increases in gas prices could cause us to incur costs in excess of what can be recovered pursuant to the current ceiling price. We are permitted to apply to the MPSC to modify the ceiling price, and will do so if necessary. In addition, if actual, prudently incurred costs exceed the ceiling price, the difference can be recovered through the reconciliation proceeding. Our GCR factor for the billing month of November 2004 is $6.55 per mcf. 2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. On December 18, 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes. On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon receipt of a letter signed by the Chairman of Consumers and CMS Energy which agrees to: - achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached, - make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted, - refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate, - prepare and file annual reports that address certain issues identified in the order, and - file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect). On October 15, 2004, Consumers' and CMS Energy's Chairman filed a letter with the MPSC making the CMS-79 CMS Energy Corporation commitments required by the rate order. On October 19, 2004, we filed rehearing petitions with the MPSC, which seek clarification of the method of computing our rate of return on common equity. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003 the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case. On October 14, 2004, the MPSC issued its Opinion and Order in our gas depreciation case. The order restores depreciation rates to the levels that were in effect prior to the issuance of the December 18, 2003 interim gas rate order. The final order further requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to have book depreciation rates restored to the level set forth in the MPSC's prior interim gas rate relief order. GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an order rejecting our filing to assess certain rates for non-physical gas title tracking services we provide. In December 2003, the FERC ruled that no refunds were at issue and we reversed a $4 million reserve related to this matter. In January 2004, three companies filed with the FERC for clarification or rehearing of the FERC's December 2003 order. In April 2004, the FERC issued its Order Granting Clarification. In that Order, the FERC indicated that its December 2003 order was in error. It directed us to file within 30 days a fair and equitable title-tracking fee and to make refunds, with interest, to customers based on the difference between the accepted fee and the fee paid. In response to the FERC's April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further Consideration in June 2004. We expect the FERC to issue an order on the merits of this proceeding. We believe that with respect to the FERC jurisdictional transportation, we have not charged any customers title transfer fees, so no refunds are due. At this time, we cannot predict the outcome of this proceeding. OTHER UNCERTAINTIES EQUATORIAL GUINEA TAX CLAIM: CMS Energy received a request for indemnification from Perenco, the purchaser of CMS Oil and Gas. The indemnification claim relates to the sale by CMS Energy of its oil, gas, and methanol projects in Equatorial Guinea and the claim of the government of Equatorial Guinea that $142 million in taxes is owed it in connection with that sale. Based on information currently available, CMS Energy and its tax advisors have concluded that the government's tax claim is without merit, and Perenco has submitted a response to the government rejecting the claim. CMS Energy cannot predict the outcome of this matter. BAY HARBOR: Certain of CMS Energy's subsidiaries participated in the development of Bay Harbor, a residential development near Petoskey, Michigan. CMS Energy has since sold its interests in Bay Harbor but on September 3, 2004, the MDEQ issued a Notice of Noncompliance (NON) directed to certain CMS Energy subsidiaries and other parties that participated in Bay Harbor regarding cement kiln dust (CKD) pile seep water contaminated with high levels of pH in Little Traverse Bay of Lake Michigan. In the various agreements to develop Bay Harbor, CMS Land Company, a subsidiary of CMS Energy (CMS Land) and CMS Energy made certain indemnifications to various parties for environmental CMS-80 CMS Energy Corporation conditions. In a settlement agreement, CMS Land abandoned all interests and rights in Bay Harbor but retained the responsibilities it and CMS Energy had under the previous environmental indemnifications. One such responsibility deals with the construction, operation and maintenance of a pH-lowering treatment facility at Bay Harbor that treats "seep water" collected after the water seeps over underground CKD piles. The "seep water" has a high pH level that requires treatment before the water can be discharged into the City of Petoskey sewer system. While the pH treatment facility was out of service for a number of months to address maintenance issues, and to resolve issues with the City of Petoskey, MDEQ found the high levels of pH in Little Traverse Bay and issued the NON. In addition, the EPA has become involved and has sent a representative to obtain samples and information concerning the site. CMS Energy is engaging in a study of the treatment facility in order to address maintenance issues over the chemical composition of the liquid being delivered to the City of Petoskey. CMS Energy has also presented plans to the MDEQ to undertake a study concerning a separate "seep" that is not currently subject to a water collection and treatment facility. Several parties have issued demand letters to CMS Land and CMS Energy claiming breach of the indemnification provisions and requesting payment of their expenses related to the NON. CMS Energy responded by stating that it had not breached its indemnity obligations; it will comply with the indemnities; it has restarted the pH treatment facility; and it has responded to the NON. CMS Energy cannot predict the outcome of this matter. INTEGRUM LAWSUIT: Integrum filed a complaint in Wayne County, Michigan Circuit Court in July 2003 against CMS Energy, Enterprises, and APT. Integrum alleges several causes of action against APT, CMS Energy, and Enterprises in connection with an offer by Integrum to purchase the CMS Pipeline Assets. In addition to seeking unspecified money damages, Integrum is seeking an order enjoining CMS Energy and Enterprises from selling, and APT from purchasing, the CMS Pipeline Assets and an order of specific performance mandating that CMS Energy, Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT and Integrum. A certain officer and director of Integrum is a former officer and director of CMS Energy, Consumers, and their subsidiaries. The individual was not employed by CMS Energy, Consumers, or their subsidiaries when Integrum made the offer to purchase the CMS Pipeline Assets. CMS Energy and Enterprises filed a motion to change the venue from Wayne County to Jackson County, which was granted. The case was then dismissed with prejudice based upon the plaintiff's failure to file a transfer fee within the requisite time. The plaintiff has stated it intends to file a motion to have the case reinstated. CMS Energy and Enterprises believe that Integrum's claims are without merit. CMS Energy and Enterprises intend to defend vigorously against this action but they cannot predict the outcome of this litigation. DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD) presented DIG with a change order to their construction contract and filed an action in Michigan state court claiming damages in the amount of $110 million, plus interest and costs, which DFD states represents the cumulative amount owed by DIG for delays DFD believes DIG caused and for prior change orders that DIG previously rejected. DFD also filed a construction lien for the $110 million. DIG, in addition to drawing down on three letters of credit totaling $30 million that it obtained from DFD, has 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. DFD has appealed the decision by the judge in the Michigan state court case to stay the litigation. DIG will continue to defend itself vigorously and pursue its claims. DIG cannot predict the outcome of this matter. DIG NOISE ABATEMENT LAWSUIT: In February 2003, DIG was served with a three-count first amended complaint filed in Wayne County Circuit Court in the matter of Ahmed, et al v. Dearborn Industrial Generation, LLC. The complaint sought damages "in excess of $25,000" and injunctive relief based upon allegations of excessive noise and vibration created by operation of the power plant. The first CMS-81 CMS Energy Corporation amended complaint was filed on behalf of six named plaintiffs, all alleged to be adjacent or nearby residents or property owners. The damages alleged were injury to persons and property of the landowners. Certification of a class of "potentially thousands" who have been similarly affected was requested. The parties entered into a settlement agreement on June 25, 2004, whereby DIG will remediate the sound emitted from various pieces of plant equipment to a level below the ambient noise level and pay a substantial portion of plaintiffs' attorney fees and costs. The court entered an Order for Conditional Class Certification and Settlement Approval on August 27, 2004. No class members opted out of the settlement. Remediation will take approximately 280 days. DIG cannot predict the final cost associated with the settlement of this matter at this time. MCV EXPANSION, LLC: Under an agreement entered into with General Electric Company (GE) in October 2002, MCV Expansion, LLC has a remaining contingent obligation to GE in the amount of $2.2 million that may become payable in the fourth quarter of 2004. The agreement provides that this contingent obligation is subject to a pro rata reduction under a formula based upon certain purchase orders being entered into with GE by June 30, 2003. MCV Expansion, LLC anticipates but cannot assure that purchase orders will be executed with GE sufficient to eliminate contingent obligations of $2.2 million. 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. Terra appealed this matter to the Michigan Court of Appeals. The Michigan Court of Appeals reversed the trial court judgment with respect to the appropriate measure of damages and remanded the case for a new trial on damages. The trial judge reinstated the judgment against Terra and awarded Terra title to the minerals. Terra has appealed this judgment. Enterprises has an indemnity obligation with regard to losses to Terra that might result from this litigation. GASATACAMA: On March 24, 2004, the Argentine Government authorized the restriction of exports of natural gas to Chile, giving priority to domestic demand in Argentina. This restriction could have a detrimental effect on GasAtacama's earnings since GasAtacama's gas-fired electric generation plant is located in Chile and uses Argentine gas for fuel. On April 21, 2004, Argentina and Bolivia signed an agreement in which Bolivian gas producers agreed to supply up to 4 million cubic feet of natural gas per day to Argentina. This gas began flowing to Argentina in mid-June and will continue to flow through November 2004. With these imports, Argentina relaxed its export restrictions to GasAtacama, currently allowing GasAtacama to receive approximately 50 percent of its contracted gas quantities at its electric generation plant. In addition, the government of Argentina and Argentine gas producers entered into an agreement to allow Argentine gas producers to raise their prices, the effect of which should help to ease Argentina's long-term gas shortage problems. Argentina and Bolivia are also currently in discussions to further extend the term and increase the volume of gas flowing to Argentina from Bolivia under the gas supply agreement, which expires in November 2004. At this point it is not possible to predict the outcome of, or the impact on GasAtacama from, these discussions or an extension of the Argentina/Bolivian gas supply agreement. Currently, management of GasAtacama is working with government officials of Chile and Argentina, as well as meeting with its electricity customers and gas producers, to attempt to mitigate the impact of a continuing gas shortage in Argentina. At this point it is not possible to predict the outcome of these events and their effect on the earnings of GasAtacama. CMS-82 CMS Energy Corporation ARGENTINA ECONOMIC SITUATION: 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 President of Argentina to renegotiate such tariffs. Effective April 30, 2002, we adopted the Argentine peso as the functional currency for our Argentine investments. We had used previously the U.S. dollar as the functional currency. As a result, we translated the assets and liabilities of our Argentine entities into U.S. dollars using an exchange rate of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign Currency Translation component of stockholders' equity of $400 million. While we cannot predict future peso-to-U.S. dollar exchange rates, we do expect that these non-cash charges reduce substantially the risk of further material balance sheet impacts when combined with anticipated proceeds from international arbitration currently in progress and political risk insurance. At September 30, 2004, the net foreign currency loss due to the unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency Translation component of stockholders' equity using an exchange rate of 3.02 pesos per U.S. dollar was $264 million. This amount also reflects the effect of recording, at December 31, 2002, U.S. income taxes on temporary differences between the book and tax bases of foreign investments, including the foreign currency translation associated with our Argentine investments. LEONARD FIELD DISPUTE: Pursuant to a Consent Judgment entered in Oakland County, Michigan Circuit Court in September 2001, CMS Gas Transmission had 18 months to extract approximately one bcf of pipeline quality natural gas held in the Leonard Field in Addison Township. The Consent Judgment provided for an extension of that period upon certain circumstances. CMS Gas Transmission has complied with the requirements of the Consent Judgment. Addison Township filed a lawsuit in Oakland County Circuit Court against CMS Gas Transmission in February 2004 alleging the Leonard Field was discharging odors in violation of the Consent Judgment. Pursuant to a Stipulated Order entered April 1, 2004, CMS Gas Transmission agreed to certain undertakings to address the odor complaints and further agreed to temporarily cease operations at the Leonard Field during the month of April 2004, the last month provided for in the Consent Judgment. Also, Addison Township was required to grant CMS Gas Transmission an extension to withdraw its natural gas if certain conditions were met. Addison Township denied CMS Gas Transmission's request for an extension on April 5, 2004. CMS Gas Transmission is pursuing its legal remedies and filed a complaint against Addison Township in June 2004. Addison Township has filed a counterclaim alleging CMS Gas Transmission has failed to remove certain equipment from the Leonard Field and that odor discharges have resulted in a diminution in surrounding property values and consequently a loss in property tax revenues. CMS Gas Transmission cannot predict the outcome of this matter, and unless an extension is provided, it will be unable to extract approximately 500,000 mcf of gas remaining in the Leonard Field. 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, including quarterly debt service payments to the Overseas Private Investment Corporation (OPIC). Enterprises is party to a Sponsor Support Agreement pursuant to which Enterprises has guaranteed CMS Ensenada's debt service payments to the OPIC up to an amount which is in dispute, but which Enterprises estimated to be CMS-83 CMS Energy Corporation approximately $9 million at June 30, 2004. Following a payment made to the OPIC in July 2004, Enterprises now believes this amount to be approximately $7 million. An interim arrangement, which provided CMS Ensenada with payments under the power purchase agreement that covered most, but not all, of CMS Ensenada's operating costs, was agreed to with YPF Repsol in 2002 but expired on December 31, 2003. Efforts to negotiate a new agreement with YPF Repsol have been unsuccessful. As a result, CMS Ensenada initiated two legal actions: (1) an ex parte action in the Argentine commercial courts, requesting injunctive relief in the form of a temporary increase in the payments by YPF Repsol under the power purchase agreement that would allow CMS Ensenada to continue to operate while seeking a final and permanent resolution; and (2) an arbitration administered by the International Chamber of Commerce seeking a ruling that the application of the Emergency Laws to the power purchase agreement is unconstitutional, or, alternatively, that the arbitral panel reestablish the economic equilibrium of the power purchase agreement, as required by the Emergency Laws taking into account that a significant portion of CMS Ensenada's operating costs are payable in U.S. dollars. In April 2004, the injunctive relief was granted on appeal, but in an amount lower than requested by CMS Ensenada. The injunctive relief expired at the end of May, but the court recently extended the term of relief until the end of the arbitration. OTHER: Certain CMS Gas Transmission and CMS Generation affiliates in Argentina received notice from various Argentine provinces claiming stamp taxes and associated penalties and interest arising from various gas transportation transactions. Although these claims total approximately $24 million, we believe the claims are without merit and will continue to contest them vigorously. CMS Generation does not currently expect to incur significant capital costs at its power facilities for compliance with current U.S. environmental regulatory standards. 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 results of operations. CMS-84 CMS Energy Corporation 4: FINANCINGS AND CAPITALIZATION Long-term debt is summarized as follows:
In Millions -------------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 -------------------------------------------------------------------------------------------------------------- CMS ENERGY CORPORATION Senior notes $ 2,063 $ 2,063 General term notes 227 496 Extendible tenor rate adjusted securities and other 186 187 -------------- -------------- Total - CMS Energy Corporation 2,476 2,746 -------------- -------------- CONSUMERS ENERGY COMPANY First mortgage bonds 2,283 1,483 Senior notes 813 1,254 Bank debt and other 356 469 Securitization bonds 406 426 FMLP debt 296 -- -------------- -------------- Total - Consumers Energy Company 4,154 3,632 -------------- -------------- OTHER SUBSIDIARIES 199 191 -------------- -------------- Principal amounts outstanding 6,829 6,569 Current amounts (565) (509) Net unamortized discount (36) (40) ----------------------------------------------------------------------------------------------------------- Total Long-term debt $ 6,228 $ 6,020 ===========================================================================================================
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB Interpretation No. 46. At September 30, 2004, long-term debt of the FMLP consists of:
In Millions --------------------------------------------------------------------------- Maturity 2004 --------------------------------------------------------------------------- 11.75% subordinated secured notes 2005 $ 70 13.25% subordinated secured notes 2006 75 6.875% tax-exempt subordinated secured notes 2009 137 6.75% tax-exempt subordinated secured notes 2009 14 --------------------------------------------------------------------------- Total amount outstanding $296 ===========================================================================
The FMLP debt is essentially project debt secured by certain assets of the MCV Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy and Consumers. CMS-85 CMS Energy Corporation The following is a summary of significant long-term debt issuances and retirements during 2004:
Principal Issue/Retirement (In millions) Interest Rate Date Maturity Date ---------------------------------------------------------------------------------------------------------------- DEBT ISSUANCES CONSUMERS ENERGY FMB $ 150 4.40% August 2004 August 2009 FMB 300 5.00% August 2004 February 2012 FMB 350 5.50% August 2004 August 2016 ---------------------------------------------------------------------------------------------------------------- Total debt issuances $ 800 ================================================================================================================ DEBT RETIREMENTS CONSUMERS ENERGY FMLP debt $ 115 11.75% July 2004 July 2004 Long-term bank debt 140 Variable August 2004 March 2009 Senior notes 141 6.50% September 2004 June 2018 Senior notes 300 6.00% September 2004 March 2005 ---------------------------------------------------------------------------------------------------------------- Total debt retirements $ 696 ================================================================================================================
Issuance costs associated with the 2004 FMB issuances total $5 million and are being amortized ratably over the lives of the related debt. Call premiums associated with the debt retirements totaled $13 million and are being amortized ratably over the lives of the newly issued debt. In September 2004, Consumers issued $30 million of 3.375 percent Limited Obligation Revenue Bonds. Consequently, Consumers redeemed $30 million of 5.8 percent Limited Obligation Revenue Bonds in October 2004. In October 2004, we issued 32.8 million shares of our common stock. We realized $288 million in net proceeds from this offering. We will use the net proceeds to make capital infusions into Consumers. Pending such capital infusions, the proceeds will be used for general corporate purposes, including temporary investments in short-term securities. DEBT MATURITIES: At September 30, 2004, the aggregate annual maturities for long-term debt for the three months ending December 31, 2004 and the next four years are:
In Millions ---------------------------------------------------------------------------------------------------------------- Payments Due ----------------------------------------------------------------- 2004 2005 2006 2007 2008 ---------------------------------------------------------------------------------------------------------------- Long-term debt $ 228 $355 $ 551 $ 554 $ 1,053 ================================================================================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers has FERC authorization to issue or guarantee up to $1.1 billion of short-term securities and up to $1.1 billion of short-term first mortgage bonds as collateral for such short-term securities. Consumers has FERC authorization to issue up to $1 billion of long-term securities for refinancing or refunding purposes, $1.5 billion of long-term securities for general corporate purposes, and $2.5 billion of long-term first mortgage bonds to be issued solely as collateral for other long-term securities. SHORT-TERM FINANCINGS: At September 30, 2004, CMS Energy had a $300 million secured revolving credit facility with banks, which expires August 3, 2007. At September 30, 2004, $92 million of letters CMS-86 CMS Energy Corporation of credit are issued and outstanding under this facility and $208 million is available for general corporate purposes, working capital, and letters of credit. At September 30, 2004, Consumers had a $500 million secured revolving credit facility with banks, which expires July 31, 2007. At September 30, 2004, $25 million of letters of credit are issued and outstanding under this facility and $475 million is available for general corporate purposes, working capital, and letters of credit. The MCV Partnership had a $50 million working capital facility available. FIRST MORTGAGE BONDS: Consumers secures its first mortgage bonds by a mortgage and lien on substantially all of its property. Its ability to issue and sell securities is restricted by certain provisions in the first mortgage bond indenture, its articles of incorporation, and the need for regulatory approvals under federal law. CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly of leased service vehicles and office furniture. As of September 30, 2004, capital lease obligations totaled $62 million. In order to obtain permanent financing for the MCV Facility, the MCV Partnership entered into a sale and lease back agreement with a lessor group, which includes the FMLP, for substantially all of the MCV Partnership's fixed assets. In accordance with SFAS No. 98, the MCV Partnership accounted for the transaction as a financing arrangement. As of September 30, 2004, finance lease obligations totaled $285 million, which represents the third-party portion of the MCV Partnership's finance lease obligation. SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we currently 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. We sold $50 million of receivables at September 30, 2004 and we sold $254 million at September 30, 2003. These sold amounts are excluded from accounts receivable on our Consolidated Balance Sheets. 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 the purchaser has no right to any receivables not sold. No gain or loss has been recorded on the receivables sold and we retain no interest in the receivables sold. Certain cash flows under our accounts receivable sales program are shown in the following table:
In Millions ------------------------------------------------------------------------------- Nine Months Ended September 30 2004 2003 ------------------------------------------------------------------------------- Net cash flow as a result of A/R financing $ (247) $ (71) Collections from customers $ 3,542 $3,379 ===============================================================================
DIVIDEND RESTRICTIONS: Our amended and restated $300 million secured revolving credit facility restricts payments of dividends on our common stock during a 12-month period to $75 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility. Under the provisions of its articles of incorporation, at September 30, 2004, Consumers had $348 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim order, which included a $190 million annual dividend cap imposed on Consumers. For the nine months ended September 30, 2004, CMS Energy received $187 million of common stock dividends from Consumers. CMS-87 CMS Energy Corporation FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: This Interpretation became effective January 2003. It describes the disclosure to be made by a guarantor about its obligations under certain guarantees that it has issued. At the beginning of a guarantee, it requires a guarantor to recognize a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provision of this Interpretation does not apply to some guarantee contracts, such as warranties, derivatives, or guarantees between either parent and subsidiaries or corporations under common control, although disclosure of these guarantees is required. For contracts that are within the recognition and measurement provision of this Interpretation, the provisions were to be applied to guarantees issued or modified after December 31, 2002. The following table describes our guarantees at September 30, 2004:
In Millions ---------------------------------------------------------------------------------------------------------------------- Issue Expiration Maximum Carrying Recourse Guarantee Description Date Date Obligation Amount(b) Provision(c) ---------------------------------------------------------------------------------------------------------------------- Indemnifications from asset sales and other agreements(a) Various Various $ 1,147 $ 2 $ - Letters of credit Various Various 163 - - Surety bonds and other indemnifications Various Various 24 - - Other guarantees Various Various 197 - - Nuclear insurance retrospective premiums Various Various 134 - - ======================================================================================================================
(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 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) The carrying amount represents the fair market value of guarantees and indemnities recorded on our balance sheet that are entered into subsequent to January 1, 2003. (c) Recourse provision indicates the approximate recovery from third parties including assets held as collateral. CMS-88 CMS Energy Corporation The following table provides additional information regarding our guarantees:
--------------------------------------------------------------------------------------------------------------------- Events That Would Require Guarantee Description How Guarantee Arose Performance --------------------------------------------------------------------------------------------------------------------- Indemnifications from asset sales and Stock and asset sales agreements Findings of misrepresentation, other agreements breach of warranties, and other specific events or circumstances Letters of credit Normal operations of coal power Noncompliance with environmental plants regulations Natural gas transportation Nonperformance Self-insurance requirement Nonperformance Nuclear plant closure Nonperformance Surety bonds and other indemnifications Normal operating activity, permits Nonperformance and license Other guarantees Normal operating activity Nonperformance or non-payment by a subsidiary under a related contract Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price-Anderson Act for nuclear incident ======================================================================================================================
We have entered into typical tax indemnity agreements in connection with a variety of transactions including transactions for the sale of subsidiaries and assets, equipment leasing, and financing agreements. These indemnity agreements generally are not limited in amount and, while a maximum amount of exposure cannot be identified, the probability of liability is considered remote. We have guaranteed payment of obligations through letters of credit, indemnities, surety bonds, and other guarantees of unconsolidated affiliates and related parties of $384 million as of September 30, 2004. We monitor and approve these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with the above obligations. CONTINGENTLY CONVERTIBLE SECURITIES: At September 30, 2004, we had contingently convertible debt and equity securities outstanding. The significant terms of these securities are as follows: Convertible Senior Notes: Our $150 million 3.375 percent convertible senior notes are putable to CMS Energy by the note holders at par on July 15, 2008, July 15, 2013 and July 15, 2018. The notes are convertible to Common Stock at the option of the holder if the price of our Common Stock remains at or above $12.81 per share for 20 of 30 consecutive trading days ending on the last trading day of a quarter. The $12.81 price per share may be adjusted if there is a payment or distribution to our Common Stockholders. If conversion were to occur, the notes would be converted into 14.1 million shares of Common Stock based on the initial conversion rate. Convertible Preferred Stock: Our $250 million 4.50 percent cumulative convertible perpetual preferred stock has a liquidation value of $50.00 per share. The security is convertible to Common Stock at the option of the holder if the price of our Common Stock remains at or above $11.87 per share for 20 of 30 consecutive trading days ending on the last trading day of a quarter. On or after December 5, 2008, we may cause the Preferred Stock to convert into Common Stock if the closing price of our Common Stock remains at or above $12.86 for 20 of any 30 consecutive trading days. The $11.87 and $12.86 prices per share may be adjusted if there is a payment or distribution to our Common Stockholders. If conversion were to occur, the securities would be converted into 25.3 million shares of Common Stock based on the CMS-89 CMS Energy Corporation initial conversion rate. At its September 2004 meeting, the EITF reached a final consensus that contingently convertible instruments should be included in the diluted earnings per share computation (if dilutive) regardless of whether the market price trigger has been met. Including the dilutive effect of these instruments could reduce our diluted earnings per share for 2004 by up to $0.10 per average common share. The effective date for this EITF Issue is for reporting periods ending after December 15, 2004, and the guidance applies to contingently convertible instruments outstanding at December 31, 2004. We plan to modify our contingently convertible securities prior to the effective date, through exchange offers that are intended to mitigate the earnings per share impact. 5: EARNINGS PER SHARE The following tables present the basic and diluted earnings per share computations:
In Millions, Except Per Share Amounts --------------------------------------------------------------------------------------------- Three Months Ended September 30 2004 2003 --------------------------------------------------------------------------------------------- EARNINGS ATTRIBUTABLE TO COMMON STOCK: Income (Loss) from Continuing Operations $ 51 $ (71) Less Preferred Dividends (3) - ---------------------------- Income (Loss) from Continuing Operations attributable to Common Stock - Basic and Diluted $ 48 $ (71) ============================ AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO BASIC AND DILUTED EPS CMS Energy: Average Shares - Basic 161.5 152.2 Add dilutive Stock Options and Warrants 0.5(a) -(a) ---------------------------- Average Shares - Diluted 162.0 152.2 ============================ EARNINGS (LOSS) PER AVERAGE COMMON SHARE ATTRIBUTABLE TO COMMON STOCK Basic $ 0.30 $ (0.47) Diluted $ 0.29 $ (0.47) =============================================================================================
CMS-90 CMS Energy Corporation
In Millions, Except Per Share Amounts ----------------------------------------------------------------------------------------------- Nine Months Ended September 30 2004 2003 ----------------------------------------------------------------------------------------------- EARNINGS ATTRIBUTABLE TO COMMON STOCK: Income (Loss) from Continuing Operations $ 68 $ (8) Less Preferred Dividends (9) - ------------------------------ Income (Loss) from Continuing Operations attributable to Common Stock - Basic and Diluted $ 59 $ (8) ============================== AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO BASIC AND DILUTED EPS CMS Energy: Average Shares - Basic 161.3 146.8 Add dilutive Stock Options and Warrants 0.5(a) -(a) ------------------------------ Average Shares - Diluted 161.8 146.8 ============================== EARNINGS (LOSS) PER AVERAGE COMMON SHARE ATTRIBUTABLE TO COMMON STOCK Basic $ 0.36 $ (0.06) Diluted $ 0.36 $ (0.06) ===============================================================================================
(a) Since the exercise price was greater than the average market price of the Common Stock, options and warrants to purchase 4.7 million shares of Common Stock were excluded from the computation of diluted EPS for the three and nine months ended September 30, 2004, compared to 5.9 million shares of Common Stock for the three months ended September 30, 2003 and 6.0 million shares of Common Stock for the nine months ended September 30, 2003. Contingently Convertible Securities: Computation of diluted earnings per share for the three months and the nine months ended September 30, 2004 excluded conversion of our $150 million 3.375 percent convertible senior notes and our 5 million shares of 4.50 percent cumulative convertible preferred stock. Both are "contingently convertible" securities and, as of September 30, 2004, none of the stated contingencies have been met. For additional details, see Note 4, Financings and Capitalization, "Contingently Convertible Securities." Trust Preferred Securities: Due to antidilution, the computation of diluted earnings per share excluded the conversion of Trust Preferred Securities into 4.2 million shares of Common Stock and a $2.2 million reduction of interest expense, net of tax, for the three months ended September 30, 2004 and the three months ended September 30, 2003, and a $6.5 million reduction of interest expense, net of tax, for the nine months ended September 30, 2004 and the nine months ended September 30, 2003. Effective July 2001, we can revoke the conversion rights if certain conditions are met. Other: In October 2004, we issued 32.8 million shares of our Common Stock. For additional details, see Note 4, Financings and Capitalization. CMS-91 CMS Energy Corporation 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 carrying amount of all long-term financial instruments, except as shown below, approximates fair value. Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $140 million as of September 30, 2004. These securities represent funds restricted primarily for future lease payments and are classified as Other Assets on our Consolidated Balance Sheets. These investments have original maturity dates of approximately one year or less and, because of their short maturities, their carrying amounts approximate their fair values. For additional details, see Note 1, Corporate Structure and Accounting Policies.
In Millions ---------------------------------------------------------------------------------------------------------------------- September 30 2004 2003 ---------------------------------------------------------------------------------------------------------------------- Fair Unrealized Fair Unrealized Cost Value Gain(Loss) Cost Value Gain(Loss) ---------------------------------------------------------------------------------------------------------------------- Long-term debt (a) $6,793 $7,111 $(318) $6,469 $6,640 $(171) Long-term debt - related parties (b) 684 647 37 - - - Trust Preferred Securities (b) - - - 663 603 60 Available-for-sale securities: Nuclear decommissioning (c) 431 551 120 450 553 103 SERP 54 65 11 55 62 7 Southern Union Stock - - - 54 54 - ======================================================================================================================
(a) Includes current maturities of $565 million at September 30, 2004 and $174 million at September 30, 2003. Settlement of long-term debt is generally not expected until maturity. (b) We determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities have been deconsolidated as of December 31, 2003 and are reflected in Long-term debt - related parties on our Consolidated Balance Sheets. For additional details, see Note 11, Implementation of New Accounting Standards. (c) Our unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities. DERIVATIVE INSTRUMENTS: 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 manage these risks 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. We may use various contracts to manage these risks including swaps, options, futures, and forward contracts. We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. Risk management contracts are classified as either trading or other than trading. These contracts contain credit risk if the counterparties, including financial institutions and energy marketers, fail to perform under the agreements. We minimize such risk by performing financial credit CMS-92 CMS Energy Corporation reviews using, among other things, publicly available credit ratings of such counterparties. Contracts used to manage interest rate, foreign currency, and commodity price risk may be considered derivative instruments that are subject to derivative and hedge accounting pursuant to SFAS No. 133. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as an asset or a liability, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in the fair value of a derivative (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income depending on whether the derivative qualifies for special hedge accounting treatment. For derivative instruments to qualify for hedge accounting under SFAS No. 133, the hedging relationship must be formally documented at inception and be highly effective in achieving offsetting cash flows or offsetting changes in fair value attributable to the risk being hedged. If hedging a forecasted transaction, the forecasted transaction must be probable. If a derivative instrument, used as a cash flow hedge, is terminated early because it is probable that a forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If a derivative instrument, used as a cash flow hedge, is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and recorded when the forecasted transaction affects earnings. We use a combination of quoted market prices and mathematical valuation models to determine fair value of those contracts requiring derivative accounting. The ineffective portion, if any, of all hedges is recognized in earnings. The majority of our contracts are not subject to derivative accounting because they qualify for the normal purchases and sales exception of SFAS No. 133, or are not derivatives because there is not an active market for the commodity. Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market, as defined by SFAS No. 133, for the coal that we purchase. If active markets develop in the future, we may be required to account for these contracts as derivatives. The mark-to-market impact on earnings related to these contracts could be material to the financial statements. The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which will include day-ahead and real-time energy market information for the MISO's participants. We are presently evaluating what impacts, if any, this market development will have on the determination of whether an active energy market exists in the state of Michigan. Derivative accounting is required for certain contracts used to limit our exposure to commodity price risk and interest rate risk. The following table reflects the fair value of all contracts requiring derivative accounting: CMS-93 CMS Energy Corporation
In Millions ---------------------------------------------------------------------------------------------------------------------------- September 30 2004 2003 ---------------------------------------------------------------------------------------------------------------------------- Fair Unrealized Fair Unrealized Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss) ---------------------------------------------------------------------------------------------------------------------------- Other than trading Gas contracts $2 $5 $3 $3 $- $(3) Interest rate risk contracts - (1) (1) - - - Derivative contracts associated with Consumers' investment in the MCV Partnership: Prior to consolidation - - - - 10 10 After consolidation: Gas fuel contracts - 80 80 - - - Gas fuel futures and swaps - 92 92 - - - Trading Electric / gas contracts (2) 10 12 - 14 14 Derivative contracts associated with equity investments in: Shuweihat - (26) (26) - (32) (32) Taweelah (35) (29) 6 - (29) (29) Jorf Lasfar - (10) (10) - (10) (10) Other - - - - (4) (4) ===========================================================================================================================
The fair value of our other than trading derivative contracts is included in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets. The fair value of our trading derivative contracts is included 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 Enterprises Investments on our Consolidated Balance Sheets. The fair value of derivative contracts associated with our investment in the MCV Partnership for 2003 is included in Investments - Midland Cogeneration Venture Limited Partnership on our Consolidated Balance Sheets. ELECTRIC CONTRACTS: Our electric utility business may use purchased electric call option contracts to meet, in part, our regulatory obligation to serve. This obligation requires us to provide a physical supply of electricity to customers, to manage electric costs, and to ensure a reliable source of capacity during peak demand periods. As of September 30, 2004 and September 30, 2003, we did not have any purchased electric call options outstanding that were accounted for as derivatives. GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas supply contracts, fixed price weather-based gas supply call options, fixed price gas supply call and put options, and other types of contracts, to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. Unrealized gains and losses associated with these options are reported directly in earnings as part of other income, and then directly offset in earnings and recorded on the balance sheet as a regulatory asset or liability as part of the GCR process. At September 30, 2004, we held fixed-priced weather-based gas supply call options and fixed-price gas supply put options. INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk associated with forecasted interest payments on variable-rate debt and to reduce the impact of interest rate fluctuations. Most of our interest rate swaps are designated as cash flow hedges. As such, we record changes in the fair value of CMS-94 CMS Energy Corporation these contracts in accumulated other comprehensive income unless the swaps are sold. For interest rate swaps that did not qualify for hedge accounting treatment, we record changes in the fair value of these contracts in Other income. The following table reflects the outstanding floating-to-fixed interest rates swaps:
In Millions ---------------------------------------------------------------------------------- Floating to Fixed Notional Maturity Fair Interest Rate Swaps Amount Date Value ---------------------------------------------------------------------------------- September 30, 2004 $ 25 2005-2006 $ (1) September 30, 2003 3 2006 - ==================================================================================
Notional amounts reflect the volume of transactions but do not represent the amount exchanged by the parties to the financial instruments. Accordingly, notional amounts do not necessarily reflect our exposure to credit or market risks. The weighted average interest rate associated with outstanding swaps was approximately 7.3 percent at September 30, 2004 and 9.0 percent at September 30, 2003. There was no ineffectiveness associated with any of the interest rate swaps that qualified for hedge accounting treatment. As of September 30, 2004, we have recorded an unrealized loss of $1 million, net of tax, in accumulated other comprehensive income related to interest rate risk contracts accounted for as cash flow hedges. We expect to reclassify $1 million of this amount as a decrease to earnings during the next 12 months primarily to offset the variable-rate interest expense on hedged debt. Certain equity method investees have issued interest rate swaps to hedge the risk associated with variable-rate debt, as listed in the table under "Derivative Instruments" within this Note. These instruments are not included in this analysis, but can have an impact on financial results. The accounting for these instruments depends on whether they qualify for cash flow hedge accounting treatment. The interest rate swaps held by Taweelah do not qualify as cash flow hedges, and therefore, we record our proportionate share of the change in the fair value of these contracts in Earnings from Equity Method Investees. The remainder of these instruments do qualify as cash flow hedges, and we record our proportionate share of the change in the fair value of these contracts in accumulated other comprehensive income. DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV PARTNERSHIP: Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that its long-term natural gas contracts, which do not contain volume optionality, qualify under SFAS No. 133 for the normal purchases and normal sales exception. Therefore, these contracts are currently not recognized at fair value on the balance sheet. Should significant changes in the level of the MCV Facility operational dispatch or purchases of long-term gas occur, the MCV Partnership would be required to re-evaluate its accounting treatment for these long-term gas contracts. This re-evaluation may result in recording mark-to-market activity on some contracts, which could add to earnings volatility. At September 30, 2004, the MCV Partnership had six long-term gas contracts that contained both an option and forward component. Because of the option component, these contracts do not qualify for the normal purchases and sales exception and are accounted for as derivatives, with changes in fair value recorded in earnings each quarter. The MCV Partnership expects future earnings volatility on these contracts, since gains or losses will be recorded each quarter. At September 30, 2004, the MCV Partnership also held three long-term gas contracts that were previously accounted for as derivatives but CMS-95 CMS Energy Corporation qualified for the normal purchases and sales exception starting in the fourth quarter of 2002. At that time, the fair value of these contracts was frozen and is being amortized over the remaining life of the contracts. For the nine months ended September 30, 2004, we recorded a $5 million net gain associated with the MCV Partnership's long-term gas fuel contracts in Fuel for electric generation on our Consolidated Statements of Income (Loss). The fair value of these contracts will reverse over the remaining life of the contracts ranging from 2004 to 2007. Gas Fuel Futures and Swaps: To manage market risks associated with the volatility of natural gas prices, the MCV Partnership maintains a gas hedging program. The MCV Partnership enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements. At September 30, 2004, the MCV Partnership held gas fuel futures and swaps. These financial instruments are accounted for as derivatives under SFAS No. 133. The contracts that are used to secure anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133. The MCV Partnership also engages in cost mitigation activities to offset the fixed charges the MCV Partnership incurs in operating the MCV Facility. These cost mitigation activities include the use of futures and options contracts to purchase and/or sell natural gas to maximize the use of the transportation and storage contracts when it is determined that they will not be needed for the MCV Facility operation. Although these cost mitigation activities do serve to offset the fixed monthly charges, these cost mitigation activities are not considered a normal course of business for the MCV Partnership and do not qualify as hedges under SFAS No. 133. Therefore, the mark-to-market gains and losses from these cost mitigation activities are recorded in earnings each quarter. As of September 30, 2004, we have recorded a cumulative net gain of $30 million, net of tax, in accumulated other comprehensive income relating to our proportionate share of the contracts held by the MCV Partnership that qualify as cash flow hedges. This balance represents natural gas futures, options, and swaps with maturities ranging from October 2004 to December 2009, of which $17 million of this gain is expected to be reclassified as an increase to earnings during the next 12 months. In addition, for the nine months ended September 30, 2004, we recorded a net gain of $21 million in earnings from hedging activities related to natural gas requirements for the MCV Facility operations and a net gain of $1 million in earnings from the MCV Partnership's cost mitigation activities. TRADING ACTIVITIES: Through December 31, 2002, our wholesale power and gas trading activities were accounted for under the mark-to-market method of accounting in accordance with EITF Issue No. 98-10. Effective January 1, 2003, EITF Issue No. 98-10 was rescinded and replaced by EITF Issue No. 02-03. As a result, only energy contracts that meet the definition of a derivative under SFAS No. 133 are to be carried at fair value. The impact of this change was recognized as a cumulative effect of a change in accounting principle loss of $23 million, net of tax, for the three month period ended March 31, 2003. During 2003, we sold a majority of our wholesale natural gas and power-trading portfolio, and exited the energy services and retail customer choice business. As a result, our trading activities have been significantly reduced. Our current activities center around entering into energy contracts that are related to the activities considered to be an integral part of our ongoing operations. We use various financial CMS-96 CMS Energy Corporation instruments, including swaps, options, futures, and forward contracts to manage commodity risks associated with generation assets owned by CMS Energy or its subsidiaries and to fulfill our contractual obligations. These contracts are classified as trading activities in accordance with EITF No. 02-03 and are accounted for using the criteria defined in SFAS No. 133. Energy trading contracts that meet the definition of a derivative are recorded as assets or liabilities in the financial statements at the fair value of the contracts. Gains or losses arising from changes in fair value of these contracts are recognized in earnings as a component of operating revenues in the period in which the changes occur. Energy trading contracts that do not meet the definition of a derivative are accounted for as executory contracts (i.e., on an accrual basis). The market prices we use to value our energy trading contracts reflect our consideration of, among other things, closing exchange and over-the-counter quotations. In certain contracts, long-term commitments may extend beyond the period in which market quotations for such contracts are available. Mathematical models are developed to determine various inputs into the fair value calculation including price and other variables that may be required to calculate fair value. Realized cash returns on these commitments may vary, either positively or negatively, from the results estimated through application of the mathematical model. Market prices are adjusted to reflect the impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. In connection with the market valuation of our energy trading contracts, we maintain reserves for credit risks based on the financial condition of counterparties. We also maintain credit policies that management believes will minimize its overall credit risk with regard to our counterparties. Determination of our counterparties' credit quality is based upon a number of factors, including credit ratings, disclosed financial condition, and collateral requirements. Where contractual terms permit, we employ standard agreements that allow for netting of positive and negative exposures associated with a single counterparty. Based on these policies, our current exposures, and our credit reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance. FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option contracts to hedge certain receivables, payables, long-term debt, and equity value relating to foreign investments. The purpose of our foreign currency hedging activities is to protect the company from the risk associated with adverse changes in currency exchange rates that could affect cash flow materially. These contracts would not subject us to risk from exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on assets and liabilities being hedged. At September 30, 2004 and September 30, 2003, we had no outstanding foreign exchange contracts. As of September 30, 2004, Taweelah, one of our equity method investees, held a foreign exchange contract that hedged the foreign currency risk associated with payments to be made under an operating and maintenance service agreement. This contract did not qualify as a cash flow hedge; and therefore, we record our proportionate share of the change in the fair value of the contract in Earnings from Equity Method Investees. CMS-97 CMS Energy Corporation 7: RETIREMENT BENEFITS We provide retirement benefits to our employees under a number of different plans, including: - non-contributory, defined benefit Pension Plan, - a cash balance pension plan for certain employees hired after June 30, 2003, - benefits to certain management employees under SERP, - health care and life insurance benefits under OPEB, - benefits to a select group of management under EISP, and - a defined contribution 401(k) plan. Pension Plan: The Pension Plan includes funds for our employees and our non-utility affiliates, including former Panhandle employees. The Pension Plan's assets are not distinguishable by company. As of September 30, 2004, we have recorded a prepaid pension asset of $392 million, $20 million of which is in Prepayments and other current assets on our Consolidated Balance Sheet. OPEB: We adopted SFAS No. 106, effective as of the beginning of 1992. Consumers 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." In 1994, the MPSC authorized recovery of the electric utility portion of these costs over 18 years and in 1996, the MPSC authorized recovery of the gas utility portion of these costs over 16 years. We have made contributions of $48 million to our 401(h) and VEBA trust funds in 2004. We plan to make additional contributions of $15 million in 2004. Costs: The following table recaps the costs incurred in our retirement benefits plans:
In Millions ----------------------------------------------------------------------------------------------------------------- Pension Three Months Ended Nine Months Ended ----------------------------------------------------------------------------------------------------------------- September 30 2004 2003 2004 2003 ----------------------------------------------------------------------------------------------------------------- Service cost $10 $ 10 $29 $ 29 Interest expense 17 18 53 55 Expected return on plan assets (26) (20) (80) (61) Amortization of: Net loss 3 2 10 7 Prior service cost 1 1 4 5 ---------------------------------------------- Net periodic pension cost $5 $ 11 $16 $ 35 =================================================================================================================
CMS-98 CMS Energy Corporation
In Millions -------------------------------------------------------------------------------------------------------------- OPEB Three Months Ended Nine Months Ended -------------------------------------------------------------------------------------------------------------- September 30 2004 2003 2004 2003 -------------------------------------------------------------------------------------------------------------- Service cost $ 5 $ 5 $ 15 $ 16 Interest expense 14 17 43 50 Expected return on plan assets (12) (11) (36) (32) Amortization of: Net loss 3 4 8 14 Prior service cost (2) (1) (7) (5) --------------------------------------------- Net periodic postretirement benefit cost $ 8 $ 14 $ 23 $ 43 ==============================================================================================================
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $158 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $18 million for the nine months ended September 30, 2004, and an expected total reduction of $24 million for 2004. The reduction of $24 million includes $7 million in capitalized OPEB costs. For additional details, see Note 11, Implementation of New Accounting Standards. 8: EQUITY METHOD INVESTMENTS Where ownership is more than 20 percent but less than a majority, 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. In 2004, net income from these investments included undistributed earnings of $13 million for the three months ended September 30, 2004 and $57 million for the nine months ended September 30, 2004. In 2003, net income from these investments included distributions in excess of earnings of $24 million for the three months ended September 30, 2003 and undistributed earnings of $45 million for the nine months ended September 30, 2003. The most significant of these investments is our: - 50 percent interest in Jorf Lasfar, - 45 percent interest in SCP, and - 40 percent interest in Taweelah. In August 2004, we sold our investment in SCP. Summarized income statement information for these equity method investments is as follows: CMS-99 CMS Energy Corporation Income Statement Data
In Millions --------------------------------------------------------------------------------------------------------- Jorf (a) Three Months Ended September 30, 2004 Lasfar SCP Taweelah Total --------------------------------------------------------------------------------------------------------- Operating revenue $ 120 $ 7 $ 26 $ 153 Operating expenses (82) (2) (8) (92) ----------------------------------------------- Operating income 38 5 18 61 Other income (expense), net (13) (2) (28) (43) ----------------------------------------------- Net income (loss) $ 25 $ 3 $ (10) $ 18 =========================================================================================================
In Millions --------------------------------------------------------------------------------------------------------- Jorf Three Months Ended September 30, 2003 Lasfar SCP Taweelah Total --------------------------------------------------------------------------------------------------------- Operating revenue $ 89 $ 15 $ 24 $ 128 Operating expenses (52) (5) (9) (66) ----------------------------------------------- Operating income 37 10 15 62 Other income (expense), net (17) (5) 14 (8) ----------------------------------------------- Net income $ 20 $ 5 $ 29 $ 54 =========================================================================================================
Income Statement Data
In Millions --------------------------------------------------------------------------------------------------------- Jorf (a) Nine Months Ended September 30, 2004 Lasfar SCP Taweelah Total --------------------------------------------------------------------------------------------------------- Operating revenue $ 332 $ 44 $ 74 $ 450 Operating expenses (203) (12) (30) (245) ----------------------------------------------- Operating income 129 32 44 205 Other expense, net (42) (14) (20) (76) ----------------------------------------------- Net income $ 87 $ 18 $ 24 $ 129 =========================================================================================================
In Millions --------------------------------------------------------------------------------------------------------- Jorf Nine Months Ended September 30, 2003 Lasfar SCP Taweelah Total --------------------------------------------------------------------------------------------------------- Operating revenue $ 270 $ 40 $ 72 $ 382 Operating expenses (138) (13) (27) (178) ----------------------------------------------- Operating income 132 27 45 204 Other expense, net (41) (14) (12) (67) ----------------------------------------------- Net income $ 91 $ 13 $ 33 $ 137 =========================================================================================================
(a) Includes results through the respective date of sale. 9: 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 the generation and distribution of electricity in the state of CMS-100 CMS Energy Corporation 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 and natural gas facilities in the United States and abroad, and - providing gas, oil, and electric marketing services to energy users. The following tables show our financial information by reportable segment. The "Other" net income segment includes corporate interest and other, discontinued operations, and the cumulative effect of accounting changes.
REVENUES In Millions ------------------------------------------------------------------------------------------------ Three Months Ended September 30 2004 2003 ------------------------------------------------------------------------------------------------ Electric utility $ 704 $ 714 Gas utility 171 164 Enterprises 188 169 -------------------------- $ 1,063 $ 1,047 ================================================================================================
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK In Millions ------------------------------------------------------------------------------------------------ Three Months Ended September 30 2004 2003 ------------------------------------------------------------------------------------------------ Electric utility $ 49 $ 59 Gas utility (11) (19) Enterprises 59 (24) Other (41) (85) -------------------------- $ 56 $ (69) ================================================================================================
REVENUES In Millions ------------------------------------------------------------------------------------------------ Nine Months Ended September 30 2004 2003 ------------------------------------------------------------------------------------------------ Electric utility $ 1,945 $ 1,966 Gas utility 1,376 1,252 Enterprises 589 923 -------------------------- $ 3,910 $ 4,141 ================================================================================================
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK In Millions ------------------------------------------------------------------------------------------------ Nine Months Ended September 30 2004 2003 ------------------------------------------------------------------------------------------------ Electric utility $ 124 $ 145 Gas utility 46 40 Enterprises 36 5 Other (141) (242) -------------------------- $ 65 $ (52) ================================================================================================
CMS-101 CMS Energy Corporation
TOTAL ASSETS In Millions ------------------------------------------------------------------------------------------------ September 30 2004 2003 ------------------------------------------------------------------------------------------------ Electric utility $ 6,972 $ 6,551 Gas utility 3,230 2,952 Enterprises 4,815 3,561 Other 360 170 -------------------------- $ 15,377 $ 13,234 ================================================================================================
10: ASSET RETIREMENT OBLIGATIONS SFAS NO. 143: This standard became effective January 2003. It 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 do so. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. Before adopting this standard, we classified the removal cost of assets included in the scope of SFAS No. 143 as part of the reserve for accumulated depreciation. For these assets, the removal cost of $448 million that was classified as part of the reserve at December 31, 2002, was reclassified in January 2003, in part, as a: - $364 million ARO liability, - $134 million regulatory liability, - $42 million regulatory asset, and - $7 million net increase to property, plant, and equipment as prescribed by SFAS No. 143. We are reflecting a regulatory asset and liability as required by SFAS No. 71 for regulated entities 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 five percent market risk premium were assumed, our current ARO liability would increase by $22 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, 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. 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 are based on decommissioning studies that largely utilize third-party cost estimates. In addition, in 2003, we recorded an ARO liability for certain pipelines and non-utility generating plants and a $1 million, net of tax, cumulative effect of change in accounting for accretion and depreciation expense for ARO liabilities incurred prior to 2003. CMS-102 CMS Energy Corporation The following tables describe our assets that have legal obligations to be removed at the end of their useful life:
September 30, 2004 In Millions --------------------------------------------------------------------------------------------------------------------- In Service Trust ARO Description Date Long Lived Assets Fund --------------------------------------------------------------------------------------------------------------------- Palisades-decommission plant site 1972 Palisades nuclear plant $500 Big Rock-decommission plant site 1962 Big Rock nuclear plant 51 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 - Closure of gas pipelines Various Gas transmission pipelines - Dismantle natural gas-fired power plant 1997 Gas fueled power plant - =====================================================================================================================
September 30, 2004 In Millions ----------------------------------------------------------------- -------------------------------------------------------------- ARO Liability ARO ------------------- Cash Flow Liability ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 9/30/04 --------------------------------------------------------------------------------------------------------------------------------- Palisades-decommission $249 $268 $ - $ - $16 $60 $344 Big Rock-decommission 61 35 - (32) 10 22 35 JHCampbell intake line - - - - - - - Coal ash disposal areas 51 52 - (2) 4 - 54 Wells at gas storage fields 2 2 - - - - 2 Indoor gas services relocations 1 1 - - - - 1 Closure of gas pipelines (a) 8 - - - - - - Natural gas-fired power plant 1 1 - - 1 - 2 ------------------------------------------------------------------------------------- Total $373 $359 $ - $(34) $31 $82 $438 =================================================================================================================================
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and CMS Field Services. The Palisades and Big Rock cash flow revisions resulted from new decommissioning reports filed with the MPSC in March 2004. The Palisades ARO also reflects a cash flow revision for the probability of operating license renewal; the renewal would extend the plant's operating license by twenty years. For additional details, see Note 3, Uncertainties, "Other Consumers' Electric Utility Uncertainties - Nuclear Plant Decommissioning." Reclassification of certain types of Cost of Removal: Beginning in December 2003, the SEC requires the quantification and reclassification of the estimated cost of removal obligations arising from other than legal obligations. These cost of removal obligations have been accrued through depreciation charges. We estimate that we had $1.026 billion at September 30, 2004 and $962 million at September 30, 2003 of previously accrued asset removal costs related to our regulated obligations arising from other than legal operations. These obligations, which were previously classified as a component of accumulated depreciation, are now classified as regulatory liabilities in the accompanying Consolidated Balance Sheets. CMS-103 CMS Energy Corporation 11: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The FASB issued this Interpretation in January 2003. The objective of the Interpretation is to assist in determining when one party controls another entity in circumstances where a controlling financial interest cannot be properly identified based on voting interests. Entities with this characteristic are considered variable interest entities. The Interpretation requires the party with the controlling financial interest, known as the primary beneficiary, in a variable interest entity to consolidate the entity. In December 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that have not previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No. 46 provided an implementation deferral until the first quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation No. 46 for all entities. We determined that we are the primary beneficiary of both the MCV Partnership and the FMLP. We have a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the MCV Facility, which results in Consumers holding a 35 percent lessor interest in the MCV Facility. Collectively, these interests make us the primary beneficiary of these entities. As such, we consolidated their assets, liabilities, and activities into our financial statements for the first time as of and for the quarter ended March 31, 2004. These partnerships have third-party obligations totaling $581 million at September 30, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.440 billion at September 30, 2004. The creditors of these partnerships do not have recourse to the general credit of CMS Energy. At December 31, 2003, we determined that we are the primary beneficiary of three other entities that are determined to be variable interest entities. We have 50 percent partnership interest 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 as defined by the Interpretation. Therefore, we consolidated these partnerships into our consolidated financial statements for the first time as of December 31, 2003. These partnerships have third-party obligations totaling $116 million at September 30, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $168 million as of September 30, 2004. Other than 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. We also determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities have been deconsolidated as of December 31, 2003. Company Obligated Trust Preferred Securities totaling $663 million, that were previously included in mezzanine equity, have been eliminated due to deconsolidation. As a result of the deconsolidation, we reflected $684 million of long-term debt - related parties and reflected an investment in related parties of $21 million. We are not required to restate prior periods for the impact of this accounting change. Additionally, we have variable interest entities in which we are not the primary beneficiary. FASB Interpretation No. 46 requires us to disclose certain information about these entities. The following chart CMS-104 CMS Energy Corporation details our involvement in these entities at September 30, 2004:
---------------------------------------------------------------------------------------------------------------------------------- Name (Ownership Nature of the Involvement Investment Balance Operating Agreement Total Generating Interest) Entity Country Date (In Millions) with CMS Energy Capacity ---------------------------------------------------------------------------------------------------------------------------------- United Arab 1999 $ 77 Yes 777 MW Taweelah (40%) Generator Emirates Generator - Under Jubail (25%) Construction Saudi Arabia 2001 $ - Yes 250 MW United Arab 2001 $ 51 (a) Yes 1,500 MW Shuweihat (20%) Generator Emirates ---------------------------------------------------------------------------------------------------------------------------------- Total $ 128 2,527 MW ==================================================================================================================================
(a) At September 30, 2004, the balance includes our proportionate share of the negative fair value of derivative instruments of $26 million. Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $128 million, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $59 million. In the third quarter of 2004, we contributed an investment of $70 million in Shuweihat. The contribution was made pursuant to the Shuweihat Shareholders' Agreement, which was entered into in 2001. FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003, we elected a one-time deferral of the accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1. The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position, No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position, No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations and postretirement benefit costs should reflect the effects of the Act. CMS-105 CMS Energy Corporation We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $158 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $18 million for the nine months ended September 30, 2004, and an expected total reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost in accordance with regulatory accounting. As such, the remeasurement resulted in a net reduction of OPEB expense of $4 million for the three months ended September 30, 2004, $13 million for the nine months ended September 30, 2004, and an expected total net expense reduction of $17 million for 2004. CMS-106 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 that provides service to customers in Michigan's Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers, the largest segment of which is the automotive industry. We manage our business by the nature and 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 services, electric power generation, gas transmission and storage, and other energy related services. Our businesses are affected by weather, especially during the traditional heating and cooling seasons, economic conditions, regulation and regulatory issues, interest rates, our debt credit rating, and energy commodity prices. Our strategy involves rebuilding our balance sheet and maintaining focus on our core strength: superior utility operation and service. Over the next few years, we expect this strategy to improve our debt ratings, grow earnings at a mid-single digit rate, and position the company to make new investments. Despite strong financial and operational performance, we face important challenges in the future. We continue to lose industrial and commercial customers to alternative electric suppliers without receiving compensation for Stranded Costs caused by the lost sales. As of October 2004, we have lost 877 MW, or 11 percent, of our electric load to these alternative electric suppliers. Based on current trends, we predict load loss by year-end to be in the range of 900 MW to 1,000 MW. However, no assurance can be made that the actual load loss will fall within that range. Existing state legislation encourages competition and provides for recovery of Stranded Costs, but the MPSC has not yet authorized Stranded Cost recovery. We continue to seek resolution of this issue through two pending Stranded Cost cases before the MPSC. In July 2004, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act. Further, higher natural gas prices have harmed the economics of the MCV Partnership and we are seeking approval from the MPSC to change the way the facility is used. Our proposal would reduce gas consumption by an estimated 30 to 40 bcf per year while improving the MCV Partnership's financial performance with no change to customer rates. A portion of the benefits from the proposal will support additional renewable resource development in Michigan. Resolving the issue is important for our shareowners and customers. We are focused on further reducing our business, financial, and regulatory risks, while growing the equity base of our company. In this regard, in August 2004, we completed an $800 million First Mortgage Bond financing at interest rates ranging from 4.4 percent to 5.5 percent and used the proceeds to retire other higher-interest rate long-term debt. Also in August 2004, we received a $150 million contribution from CE-1 Consumers Energy Company CMS Energy, providing additional liquidity and flexibility for our operations. The result of these efforts, and others, will be a strong, reliable utility company that will be poised to take advantage of opportunities for further growth. CONSOLIDATION OF THE MCV PARTNERSHIP AND THE FMLP Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the MCV Partnership and the FMLP. As a result, we have consolidated the assets, liabilities, and activities of these entities into our financial statements as of and for the three and nine months ended September 30, 2004. These entities are reported as equity method investments in our financial statements as of and for the three and nine months ended September 30, 2003. The consolidation of these entities had no impact on our consolidated net income for the three and nine months ended September 30, 2004 versus the same periods ended September 30, 2003. For additional details, see Note 7, Implementation of New Accounting Standards. FORWARD-LOOKING STATEMENTS AND RISK FACTORS This Form 10-Q 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: - capital and financial market conditions, including the current price of CMS Energy Common Stock and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets as well as 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, CE-2 Consumers Energy Company - the extent of favorable regulatory treatment and regulatory lag concerning a number of significant questions presently before the MPSC relating to the Customer Choice Act including: - recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers, - recovery of Clean Air Act costs and other environmental and safety-related expenditures, - power supply and natural gas supply costs when energy supply and oil prices are rapidly increasing, - timely recognition in rates of additional equity investments in Consumers, and - adequate and timely recovery of additional electric and gas rate-based expenditures, - the impact of adverse natural gas prices on the MCV Partnership investment, regulatory decisions concerning the MCV Partnership RCP, and regulatory decisions that limit our recovery of capacity and fixed energy payments, - federal regulation of electric sales and transmission of electricity including re-examination by federal regulators of our market-based sales authorizations in wholesale power markets without price restrictions, - energy markets, including 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 problems, or other developments, - the GAAP requirement that we utilize mark-to-market accounting on certain of our energy commodity contracts, and possibly other types of contracts in the future, which may have a negative effect on earnings and could add to earnings volatility, - 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, 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, - outcome, cost, and other effects of legal and administrative proceedings, settlements, investigations and claims, - 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, - 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, and many of which are beyond our control. CE-3 Consumers Energy Company RESULTS OF OPERATIONS NET INCOME AVAILABLE TO COMMON STOCKHOLDER
In Millions ------------------------------------------------------------------------------------------------------------- September 30 2004 2003 Change ------------------------------------------------------------------------------------------------------------- Three months ended $ 34 $ 33 $ 1 Nine months ended 162 172 (10) =============================================================================================================
2004 COMPARED TO 2003: For the three months ended September 30, 2004, our net income increased $1 million versus the same period in 2003 primarily due to increases in gas revenues, electric fuel recovery revenues, earnings from the MCV Partnership, reductions in general tax expense, and increased interest income. The annual unbilled gas volume analysis led to an increase in accrued gas revenues of $7 million versus the 2003 results. In addition, gas revenues increased net income $1 million due to the interim MPSC gas rate order issued in December 2003. The Customer Choice Act authorized us to recognize interest income on the excess of capital expenditures over our depreciation base. The increase in interest income offset higher operating expenses, benefiting net income $4 million. Net income also increased $1 million versus the same period in 2003 due to the absence of a prior year underrecovery of PSCR revenue versus cost. Further, net income increased $3 million due to a decrease in general taxes from decreased property tax expense. Finally, net income increased $2 million due to higher earnings from the MCV Partnership reflecting increases in the fair value of certain long-term gas contracts. Decreased electric delivery revenues and increased interest charges substantially offset these increases to net income. Decreased electric delivery revenues reduced net income by $13 million, primarily due to milder summer temperatures, tariff revenue reductions, and the continued loss of commercial and industrial customers switching to alternative electric suppliers, as allowed by the Customer Choice Act. An increase in interest expense decreased net income $4 million due to greater average borrowings, partially offset by a reduction in the average rate of interest. For the nine months ended September 30, 2004, our net income decreased $10 million versus the same period in 2003. Electric delivery revenues decreased net income $28 million due to milder summer weather, tariff revenue reductions, and the continued loss of customers to alternative electric suppliers, as allowed by the Customer Choice Act. The milder weather lowered gas delivery revenues, decreasing net income by $7 million. Earnings from the MCV Partnership declined $6 million primarily due to increases in non-recoverable fuel costs incurred at the MCV Facility. In addition, net income was decreased $12 million due to higher interest expense from greater average borrowings, partially offset by a reduction in our average interest rate. Higher general taxes decreased net income $7 million due to a 2003 reduction in MSBT expense to reflect the benefit of CMS Energy's receipt of approval to file consolidated tax returns for the years 2000 and 2001. Further, in 2003, under provisions of the Customer Choice Act, the excess or recovery of PSCR revenues over PSCR costs benefited net income. In contrast, in 2004, PSCR overrecoveries must be reserved for possible future refund and consequently, do not benefit net income. This change in the treatment of PSCR overrecoveries reduced net income $2 million. Partially offsetting these reductions to net income were $31 million in benefits relating primarily to reduced depreciation expense and increases in interest income. The Customer Choice Act authorized us to defer electric depreciation on the excess of capital expenditures over our depreciation base and recognize interest income on the excess capital expenditures. Gas depreciation expense also declined in the nine months ended September 30, 2004 versus the same period in 2003 due to the interim MPSC gas rate order CE-4 Consumers Energy Company issued in December 2003. This interim order also authorized a gas rate increase that benefited net income by $8 million. Finally, net income benefited from the absence of a $12 million charge taken in 2003. The 2003 charge reflected a decline in the market value of CMS Energy stock held by us. For additional details, see "Electric Utility Results of Operations" and "Gas Utility Results of Operations" within this section and Note 2, Uncertainties. ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions ---------------------------------------------------------------------------------------------------------------- September 30 2004 2003 Change ---------------------------------------------------------------------------------------------------------------- Three months ended $ 49 $ 59 $ (10) Nine months ended 124 145 (21) ================================================================================================================
Three Months Ended Nine Months Ended Reasons for the change: September 30, 2004 vs. 2003 September 30, 2004 vs. 2003 ---------------------------------------------------------------------------------------------------------------- Electric deliveries $(20) $(43) Power supply costs and related revenue 2 (3) Other operating expenses, non-commodity revenue and other income 3 29 General taxes 2 (8) Fixed charges (3) (9) Income taxes 6 13 ----------------------------------------------------------- Total change $(10) $(21) ================================================================================================================
ELECTRIC DELIVERIES: Electric deliveries, including transactions with wholesale marketers, other electric utilities, and customers choosing alternative suppliers decreased 0.02 billion kWh or 0.2 percent, in the three months ended September 30, 2004 versus the same period in 2003. For the nine months ended September 30, 2004, electric deliveries increased 1.0 billion kWh or 3.5 percent versus the same period in 2003. Electric delivery revenues benefited from the recovery of deferred implementation costs. Recovery of these costs began July 1, 2004 and partially offset revenue reductions attributable to milder summer temperatures, decreased revenues attributable to customers choosing alternative electric suppliers, and tariff revenue reductions. The tariff revenue reductions began January 1, 2004, and were equivalent to the Big Rock nuclear decommissioning surcharge in effect when our electric retail rates were frozen from September 2000 through December 31, 2003. The tariff revenue reductions decreased electric delivery revenue by approximately $9 million in the three months ended September 30, 2004, and $27 million in the nine months ended September 30, 2004 versus the same periods in 2003. The tariff revenue reductions are expected to decrease electric delivery revenue by $35 million for the full year of 2004 versus the full year of 2003. On the positive side, the tariff revenue reductions were reclassified for capped customers as power supply revenue and helped reduce the underrecovery of power supply costs for these customers. CE-5 Consumers Energy Company POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost recovery rate was a fixed amount per kWh, as required under the Customer Choice Act. Therefore, power supply-related revenue in excess of actual power supply costs increased operating income. By contrast, if power supply-related revenue had been less than actual power supply costs, the underrecovery would have decreased operating income. In 2004, our recovery of power supply costs is no longer fixed, but is instead restricted to a pre-defined limit for certain customer classes. The customer classes that have a pre-defined limit, or cap, on the level of power supply costs they can be charged are primarily the residential and small commercial customer classes. In 2004, to the extent our power supply-related revenue exceeds actual power supply costs, this former benefit is reserved for possible future refund. Prior to a refund, a reserve is decreased for subsequent underrecoveries before possibly decreasing operating income. In the three months ended September 30, 2004, we have been able to reverse revenues previously reserved in the year and defer certain costs to reduce the impact of underrecoveries on operating income. Consequently, in the three months ended September 30, 2004, operating income increased versus the same period in 2003 due to a prior year underrecovery of power supply costs. Operating income decreased for the nine months ended September 30, 2004 versus the same period in 2003 due to prior year power supply cost overrecoveries. OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the three months ended September 30, 2004, other operating expenses increased $8 million, non-commodity revenue decreased $2 million, and other income increased $13 million versus the same period in 2003. The increase in other income relates primarily to the accrual of interest income on capital expenditures in excess of depreciation, as allowed by the Customer Choice Act. Higher operating expenses reflect increased generating plant operating costs and amortization relating to the recovery of deferred implementation costs, which began July 1, 2004. Decreased non-commodity revenues primarily reflect a reduction in rent revenues. In the nine months ended September 30, 2004, other operating expenses increased $2 million, other income increased $33 million, and non-commodity revenue decreased $2 million versus the same period in 2003. The increase in other income relates primarily to the accrual of interest income on capital expenditures in excess of depreciation, as allowed by the Customer Choice Act. A decline in non-commodity revenues reflects reduced rent revenues in the nine months ended September 30, 2004 versus the same period in 2003. GENERAL TAXES: General taxes decreased in the three months ended September 30, 2004 versus the same period in 2003. This decrease reflects less MSBT expense and reduced property tax expense. General taxes increased in the nine months ended September 30, 2004 versus the same period in 2003 primarily due to reductions in the MSBT expense in 2003. The 2003 reduction was primarily due to CMS Energy's receipt of approval to file consolidated tax returns for the years 2000 and 2001. The taxable income for these years was lower than the amount used to make estimated MSBT payments. These returns were filed in the second quarter of 2003. FIXED CHARGES: Fixed charges increased in the three and nine months ended September 30, 2004 versus the same periods in 2003 due to higher average debt levels, partially offset by a reduction in the average rate of interest. In the three months ended September 30, 2004, the average rate of interest dropped 14 basis points and in the nine months ended September 30, 2004, the average rate of interest dropped 45 basis points versus the same periods in 2003. This decrease in the average rates incorporates the impact of an August 2004 refinancing of $800 million. This refinancing both extended the maturity of the debt, and significantly decreased the long-term debt interest rates of the $800 million. CE-6 Consumers Energy Company INCOME TAXES: In the three and nine months ended September 30, 2004, income taxes decreased versus the same periods in 2003 primarily due to lower earnings by the electric utility, and the OPEB Medicare Part D federal subsidy that is exempt from federal taxation. GAS UTILITY RESULTS OF OPERATIONS
In Millions ------------------------------------------------------------------------------------------------------------- September 30 2004 2003 Change ------------------------------------------------------------------------------------------------------------- Three months ended $ (11) $(19) $8 Nine months ended 46 40 6 =============================================================================================================
Three Months Ended Nine Months Ended Reasons for the change: September 30, 2004 vs. 2003 September 30, 2004 vs.2003 ------------------------------------------------------------------------------------------------------------- Gas deliveries $10 $(11) Gas rate increase 1 12 Gas wholesale and retail services and other gas revenues - 3 Operation and maintenance (1) (3) Depreciation 2 9 General taxes 2 (2) Fixed charges (3) (9) Income taxes (3) 7 ----------------------------------------------------------- Total change $ 8 $ 6 =============================================================================================================
GAS DELIVERIES: For the three months ended September 30, 2004, the higher priced non-transportation gas deliveries decreased 0.3 bcf or 1.7 percent versus the same period in 2003. The lower priced transportation gas deliveries to end-use customers decreased 0.6 bcf or 5.3 percent. Despite the decrease in gas deliveries, gas delivery revenue increased in the three months ended September 30, 2004 versus the same period in 2003. This increase reflects the effect of the annual unbilled gas volume analysis on accrued gas revenues versus the 2003 results. In 2004, this analysis supported an increase in unbilled gas volumes that resulted in an increase of accrued gas revenues. In 2003, this annual analysis led to a reduction in accrued gas revenues. For the nine months ended September 30, 2004, gas deliveries, including transportation to end-use customers, decreased 17.8 bcf or 7.5 percent versus the same period in 2003 primarily due to milder weather. GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order authorizing a $19 million annual increase to gas tariff rates. As a result of this order, gas revenues increased for the three and nine months ended September 30, 2004 versus the same periods in 2003. GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the nine months ended September 30, 2004, wholesale and retail services and other gas revenues increased primarily due to increased storage revenue versus the same period in 2003. CE-7 Consumers Energy Company OPERATION AND MAINTENANCE: For the three and nine months ended September 30, 2004, increased expenditures on safety, reliability, and customer service were offset partially by reduced benefit costs compared to the same periods in 2003. DEPRECIATION: For the three and nine months ended September 30, 2004, depreciation expense decreased versus the same periods in 2003. The decrease in depreciation expense relates to a reduction in depreciation rates authorized by the MPSC's December 2003 interim rate order. GENERAL TAXES: General taxes decreased in the three months ended September 30, 2004 versus the same period in 2003. This decrease reflects less MSBT expense and decreased property tax expense. For the nine months ended September 30, 2004, general tax expense increased $2 million due to higher MSBT expense versus the same period in 2003. The increase in MSBT expense is primarily due to CMS Energy's receipt of approval to file consolidated tax returns for the years 2000 and 2001. The taxable income for these years was lower than the amount used to make estimated MSBT payments. These returns were filed in the second quarter of 2003. FIXED CHARGES: Fixed charges increased in the three and nine months ended September 30, 2004 versus the same periods in 2003 due to higher average debt levels, partially offset by a reduction in the average rate of interest. In the three months ended September 30, 2004, the average rate of interest dropped 14 basis points and in the nine months ended September 30, 2004, the average rate of interest dropped 45 basis points versus the same periods in 2003. This decrease in the average rates incorporates the impact of an August 2004 refinancing of $800 million. This refinancing both extended the maturity of the debt, and significantly decreased the long-term debt interest rates of the $800 million. INCOME TAXES: For the three months ended September 30, 2004, income taxes increased primarily due to the increased earnings of the gas utility versus the same period in 2003. For the nine months ended September 30, 2004, income taxes decreased due to the income tax treatment of items related to plant, property and equipment as required by past MPSC rulings, the decreased earnings of the gas utility, and the OPEB Medicare Part D federal subsidy that is exempt from federal taxation. 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: - use of estimates in accounting for contingencies and equity method investments, - accounting for the effects of industry regulation, - accounting for financial and derivative instruments, - accounting for pension and postretirement benefits, - accounting for asset retirement obligations, - accounting for nuclear decommissioning costs, and - accounting for related party transactions. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies. CE-8 Consumers Energy Company USE OF ESTIMATES AND ASSUMPTIONS In preparing our financial statements, we use estimates and assumptions that may affect reported amounts and disclosures. Accounting estimates are used 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. There are risks and uncertainties that may cause actual results to differ from estimated results, 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 the occurrence is probable and, where determinable, an estimate of the liability amount. The recording of estimated liabilities for contingencies is guided by the principles in SFAS No. 5. We consider many factors in making these assessments, including history and the specifics of each matter. The most significant of these contingencies are our electric and gas environmental estimates, which are discussed in the "Outlook" section included in this MD&A, and the potential underrecoveries from our power purchase contract with the MCV Partnership. MCV UNDERRECOVERIES: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990 and to supply electricity and steam to Dow. We hold a 49 percent partnership interest in the MCV Partnership, and a 35 percent lessor interest in the MCV Facility. Under our PPA with the MCV Partnership, we pay a capacity charge based on the availability of the MCV Facility whether or not electricity is actually delivered to us; a variable energy charge for kWh delivered to us; and a fixed energy charge based on availability up to 915 MW and based on delivery for the remaining 325 MW of contract capacity. The cost that we incur under the MCV Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity and fixed energy payments will aggregate $206 million from 2004 through 2007. For capacity and fixed energy payments billed by the MCV Partnership after September 15, 2007, and not recovered from customers, we expect to claim relief under a regulatory out provision under the MCV Partnership PPA. This provision obligates Consumers to pay the MCV Partnership only those capacity and energy charges that the MPSC has authorized for recovery from electric customers. The effect of any such action would be to: - reduce cash flow to the MCV Partnership, which could have an adverse effect on our investment, and - eliminate our underrecoveries for capacity and fixed energy payments. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. CE-9 Consumers Energy Company As a result of returning to the PSCR process on January 1, 2004, we returned to dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in order to maximize recovery from electric customers of our capacity and fixed energy payments. This fixed load dispatch increases the MCV Facility's output and electricity production costs, such as natural gas. As the spread between the MCV Facility's variable electricity production costs and its energy payment revenue widens, the MCV Partnership's financial performance and our investment in the MCV Partnership is and will be impacted negatively. In February 2004, we filed the RCP with the MPSC that is intended to help conserve natural gas and thereby improve our investment in the MCV Partnership, without raising the costs paid by our electric customers. The plan's primary objective is to dispatch the MCV Facility on the basis of natural gas market prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit Consumers' ownership interest in the MCV Partnership. In August 2004, several qualifying facilities sought and obtained a stay of the RCP proceeding from the Ingham County Circuit Court after their previous attempt to intervene in the proceeding was denied by the MPSC. In an attempt to resolve this intervention issue as quickly as possible, the MPSC issued an order permitting the qualifying facilities to participate as intervenors. As a result, the Ingham County Circuit Court stay was lifted and hearings were completed in October 2004. The MPSC has decided to dispense with a Proposal for Decision from the presiding ALJ and will issue a decision directly. We cannot predict if or when the MPSC will approve the RCP. The two most significant variables in the analysis of the MCV Partnership's future financial performance are the forward price of natural gas for the next 20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of capacity and fixed energy payments. Historically, natural gas prices have been volatile. Presently, there is no consensus in the marketplace on the price or range of future prices of natural gas. Even with an approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment of our investment in the MCV Partnership. We presently cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our investment in the MCV Partnership. For additional details on the MCV Partnership, see Note 2, Uncertainties, "Other Electric Uncertainties - The Midland Cogeneration Venture." 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, items that a non-regulated entity normally would expense, we may record as regulatory assets if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, items that non-regulated entities may normally recognize as revenues, we may record as regulatory liabilities if the actions of the regulator indicate they will require such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. As of September 30, 2004, we had $1.158 billion recorded as regulatory assets and $1.512 billion recorded as regulatory liabilities. For additional details on industry regulation, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." CE-10 Consumers Energy Company ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities using SFAS No. 115. Debt and equity securities can be classified into one of three categories: held-to-maturity, trading, or available-for-sale. Our debt securities are classified as held-to-maturity securities and are reported at cost. Our investments in equity securities are classified as available-for-sale securities and are reported at fair value determined from quoted market prices. Any unrealized gains and losses resulting from changes in fair value are reported in equity as part of accumulated other comprehensive income. Unrealized gains and losses are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses resulting from changes in the fair value of our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as an asset or a liability at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in the fair value of a derivative (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income, depending on whether the derivative qualifies for special hedge accounting treatment. The types of contracts we typically classify as derivative instruments are interest rate swaps, electric call options, gas fuel futures and swaps, gas fuel options, gas fuel contracts containing volume optionality, fixed priced weather-based gas supply call options, and fixed price gas supply call and put options. We generally do not account for electric capacity and energy contracts, gas supply contracts, coal and nuclear fuel supply contracts, or purchase orders for numerous supply items as derivatives. The majority of our contracts are not subject to derivative accounting because they qualify for the normal purchases and sales exception of SFAS No. 133, or are not derivatives because there is not an active market for the commodity. Our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market, as defined by SFAS No. 133, for the coal that we purchase. If active markets develop in the future, we may be required to account for these contracts as derivatives. The mark-to-market impact on earnings related to these contracts could be material to our financial statements. The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which will include day-ahead and real-time energy market information for the MISO's participants. We are presently evaluating what impacts, if any, this market development will have on the determination of whether an active energy market exists in the state of Michigan. For additional information, see Electric Business Uncertainties, "Transmission Market Developments" within this MD&A. The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that its long-term natural gas contracts, which do not contain volume optionality, qualify under SFAS No. 133 for the normal purchases and normal sales exception. Therefore, these contracts are currently not recognized at fair value on the balance sheet. Should significant changes in the level of the MCV Facility operational dispatch or purchases of long-term gas occur, the MCV Partnership would be required to re-evaluate its accounting treatment for these long-term gas contracts. This re-evaluation may result in recording mark-to-market activity on some contracts, which could add to earnings volatility. CE-11 Consumers Energy Company To determine the fair value of contracts that are accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward prices, strike prices, volatilities, interest rates, and maturity dates. Changes in forward prices or volatilities could change significantly the calculated fair value of certain contracts. At September 30, 2004, we assumed a market-based interest rate of 1 percent and monthly volatility rates ranging between 43 percent and 57 percent to calculate the fair value of our gas options. At September 30, 2004, we assumed market-based interest rates ranging between 1.84 percent and 3.90 percent (depending on the term of the contract) and monthly volatility rates ranging between 34 percent and 63 percent to calculate the fair value of the gas fuel derivative contracts held by the MCV Partnership. 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 manage these risks 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. We may use various contracts to manage these risks, including swaps, options, futures, and forward contracts. Contracts used to manage market risks may be considered derivative instruments that are subject to derivative and hedge accounting pursuant to SFAS No. 133. We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. We enter into all risk management contracts for purposes other than trading. These contracts contain credit risk if the counterparties, including financial institutions and energy marketers, fail to perform under the agreements. We minimize such risk by performing financial credit reviews using, among other things, publicly available credit ratings of such counterparties. We perform sensitivity analyses to assess the potential loss in fair value, cash flows, or future earnings based upon a hypothetical 10 percent adverse change in market rates or prices. We do not believe that sensitivity analyses alone provide an accurate or reliable method for monitoring and controlling risks. Therefore, we use our experience and judgment to revise strategies and modify assessments. Changes in excess of the amounts determined in sensitivity analyses could occur if market rates or prices exceed the 10 percent shift used for the analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity Price Risk," and "Investment Securities Price Risk" within this section. 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 a 10 percent adverse change in market interest rates):
In Millions ---------------------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 ---------------------------------------------------------------------------------------------------------------------- Variable-rate financing - before tax annual earnings exposure $ 1 $ 1 Fixed-rate financing - potential loss in fair value (a) 168 154 ======================================================================================================================
(a) Fair value exposure would only be realized if we repurchased all of our fixed-rate financing. Commodity Price Risk: For purposes other than trading, we enter into electric call options, fixed-priced weather-based gas supply call options, and fixed-priced gas supply call and put options. Electric call CE-12 Consumers Energy Company options are purchased to protect against the risk of fluctuations in the market price of electricity, and to ensure a reliable source of capacity to meet our customers' electric needs. Purchased electric call options give us the right, but not the obligation, to purchase electricity at predetermined fixed prices. Our gas supply call and put options are used to purchase reasonably priced gas supply. Purchases of gas supply call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Gas supply put options sold give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices. At September 30, 2004, we held fixed-priced weather-based gas supply call options and fixed-price gas supply put options. The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation and to manage gas fuel costs. Some of these contracts contain volume optionality and, therefore, are treated as derivative instruments. Also, the MCV Partnership enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements. At September 30, 2004, the MCV Partnership held gas fuel contracts with volume optionality, as well as gas fuel futures and swaps. Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions -------------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 -------------------------------------------------------------------------------------------------------------- Potential reduction in fair value: Gas supply option contracts $ 3 $ 1 Derivative contracts associated with Consumers' investment in the MCV Partnership: Gas fuel contracts 22 N/A Gas fuel futures and swaps 48 N/A ==============================================================================================================
We did not perform a sensitivity analysis for the derivative contracts held by the MCV Partnership as of December 31, 2003 because the MCV Partnership was not consolidated into our financial statements until March 31, 2004, as discussed in Note 7, Implementation of New Accounting Standards. Investment Securities Price Risk: We are exposed to price risk associated with investments in equity securities. As discussed in "Financial Instruments" within this section, our investments in equity securities are classified as available-for-sale securities. They are reported at fair value, with any unrealized gains or losses resulting from changes in fair value reported in equity as part of accumulated other comprehensive income. Unrealized gains and losses are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses resulting from changes in the fair value of our nuclear decommissioning investments are reflected as regulatory liabilities in our Consolidated Balance Sheets. Our debt securities are classified as held-to-maturity securities and have original maturity dates of approximately one year or less. Because of the short maturity of these instruments, their carrying amounts approximate their fair values. CE-13 Consumers Energy Company Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions ------------------------------------------------------------------------------------------------------------- September 30, 2004 December 31, 2003 ------------------------------------------------------------------------------------------------------------- Potential reduction in fair value: Nuclear decommissioning investments $ 54 $ 57 Other available-for-sale investments 4 4 =============================================================================================================
For additional details on market risk and derivative activities, see Note 4, Financial and Derivative Instruments. ACCOUNTING FOR PENSION AND OPEB Pension: We have established external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. We implemented a cash balance plan for certain employees hired after June 30, 2003. We use SFAS No. 87 to account for pension costs. 401(k): In our effort to reduce costs, the employer's match for the 401(k) plan was suspended effective September 1, 2002. It is scheduled to resume on January 1, 2005. OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. We use SFAS No. 106 to account for other postretirement benefit costs. Liabilities for both pension and OPEB are recorded on the balance sheet at the present value of their future obligations, net of any plan assets. The calculation of the liabilities and associated expenses requires the expertise of actuaries. Many assumptions are made 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. Any change in these assumptions can change significantly the liability and associated expenses recognized in any given year. The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
In Millions ------------------------------------------------------------------------------------------------------------- Expected Costs Pension Cost OPEB Cost Contributions ------------------------------------------------------------------------------------------------------------- 2004 $20 $30 $ 62 2005 49 39 78 2006 68 35 110 =============================================================================================================
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. As of September 30, 2004, we have a prepaid pension asset of $369 million, $20 million of which is in Other current assets on our Consolidated Balance Sheets. CE-14 Consumers Energy Company Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated pension cost for 2004 by $2 million. Lowering the discount rate by 0.25 percent (from 6.25 percent to 6.00 percent) would increase estimated pension cost for 2004 by $4 million. The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated, retroactively, the effects of the subsidy into our financial statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $148 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $17 million for the nine months ended September 30, 2004, and an expected total reduction of $23 million for 2004. For additional details on postretirement benefits, see Note 5, Retirement Benefits, and Note 7, Implementation of New Accounting Standards. ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS SFAS No. 143 became effective January 2003. It 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, 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. 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 are based on decommissioning studies, which largely utilize third-party cost estimates. For additional details on ARO, see Note 6, Asset Retirement Obligations. CE-15 Consumers Energy Company ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS The MPSC and the FERC regulate the recovery of costs to decommission our Big Rock and Palisades nuclear plants. We have established 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. 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 have helped us develop decommissioning cost estimates. Various inflation rates for labor, non-labor, and contaminated equipment disposal costs are used 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 fuel from the sites, as required by the Nuclear Waste Policy Act of 1982. The decommissioning trust funds include equities and fixed income investments. Equities will be converted to fixed income investments during decommissioning, and fixed income investments are converted to cash as needed. In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. The funds provided by the trusts, additional customer surcharges, and potential funds from the DOE litigation are all required to cover fully the decommissioning costs. 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 fully fund the decommissioning of Big Rock or Palisades. 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. We will also seek additional relief from the MPSC. For additional details on nuclear decommissioning, see Note 2, Uncertainties, "Other Electric Uncertainties - Nuclear Plant Decommissioning" and "Nuclear Matters." 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 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 are generally based on regulated prices, market prices, or competitive bidding. Transactions involving the power supply purchases from certain affiliates CE-16 Consumers Energy Company 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. CAPITAL RESOURCES AND LIQUIDITY Our liquidity and capital requirements are a function of our results of operations, capital expenditures, contractual obligations, debt maturities, 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. The market price for natural gas has increased. Although our natural gas purchases are recoverable from our customers, the amount paid for natural gas stored as inventory could require additional liquidity due to the timing of the cost recoveries. In addition, a few of our commodity suppliers have requested advance payment or other forms of assurances, including margin calls, in connection with maintenance of ongoing deliveries of gas and electricity. Our current financial plan includes controlling our operating expenses and capital expenditures and evaluating market conditions for financing opportunities. We believe our current level of cash and borrowing capacity, along with anticipated cash flows from operating and investing activities, will be sufficient to meet our liquidity needs through 2005. CASH POSITION, INVESTING, AND FINANCING SUMMARY OF CASH FLOWS:
In Millions ------------------------------------------------------------------------------- Nine Months Ended September 30 2004 2003 ------------------------------------------------------------------------------- Net cash provided by (used in): Operating activities $ 330 $ 143 Investing activities (427) (327) Financing activities 10 100 ----------------------------- Net Decrease in Cash and Cash Equivalents $ (87) $ (84) ================================================================================
OPERATING ACTIVITIES: For the nine months ended September 30, 2004, net cash provided by operating activities increased $187 million versus the same period in 2003. The absence, in 2004, of $172 million in pension contributions made in 2003, increases in inventory due to decreased economic demand for gas, and increases in other liabilities resulting from the consolidation of the MCV Partnership and the FMLP, and other timing differences represent the majority of the increase. These increases more than offset the $157 million increase in accounts receivable primarily due to lower sales of accounts receivable resulting from our improved liquidity. INVESTING ACTIVITIES: For the nine months ended September 30, 2004, net cash from investing activities decreased $100 million versus the same period in 2003 due to an increase in capital expenditures of $62 million and an increase in the amount of cash restricted of $33 million. For additional details on restricted cash, see Note 1, Corporate Structure and Accounting Policies, "Cash Equivalents and Restricted Cash." CE-17 Consumers Energy Company FINANCING ACTIVITIES: For the nine months ended September 30, 2004, net cash provided by financing activities decreased $90 million versus the same period in 2003 primarily due to a decrease of $216 million in net proceeds from borrowings. This decrease was offset by a $150 million stockholder's contribution from the parent. For additional details on long-term debt activity, see Note 3, Financings and Capitalization. OBLIGATIONS AND COMMITMENTS REGULATORY AUTHORIZATION FOR FINANCINGS: We issue short- and long-term securities under the FERC's authorization. For additional details of our existing authorization, see Note 3, Financings and Capitalization. LONG-TERM DEBT: The components of long-term debt are presented in Note 3, Financings and Capitalization. SHORT-TERM FINANCINGS: At September 30, 2004, we had $475 million available and the MCV Partnership had $50 million available in short-term credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. Additional details on short-term financings are presented in Note 3, Financings and Capitalization. OFF-BALANCE SHEET ARRANGEMENTS: SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we may sell up to $325 million of certain accounts receivable. For additional details, see Note 3, Financings and Capitalization. CONTINGENT COMMITMENTS: Our contingent commitments include indemnities and letters of credit. Indemnities are agreements to reimburse other companies, such as an insurance company, if those companies have to complete our contractual performance in a third-party contract. 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 and approve these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. Our off-balance sheet commitments at September 30, 2004 will expire as follows:
Contingent Commitments In Millions --------------------------------------------------------------------------------------------------------------- Commitment Expiration -------------------------------------------------------- 2009 and Total 2004 2005 2006 2007 2008 beyond --------------------------------------------------------------------------------------------------------------- Off-balance sheet: Surety bonds and other indemnifications (a) $ 5 $ - $ - $ - $ - $ - $ 5 Letters of credit (b) 25 - 18 - - - 7 ===============================================================================================================
(a) The surety bonds are continuous in nature. The need for the bonds is determined on an annual basis. In the third quarter of 2004, $3 million in surety bonds were not renewed. (b) The $2 million letter of credit for workers compensation self insurance and $5 million of MDEQ letters of credit are renewed annually. CE-18 Consumers Energy Company DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at September 30, 2004, we had $348 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim order, which included a $190 million annual dividend cap. For the nine months ended September 30, 2004, we paid $187 million in common stock dividends to CMS Energy. OUTLOOK ELECTRIC BUSINESS OUTLOOK GROWTH: Over the next five years, we expect electric deliveries to grow at an average rate of approximately two percent per year, based primarily on a steadily growing customer base and economy. 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 fluctuations in weather conditions and changes in economic conditions, including utilization and expansion of manufacturing facilities. We experienced less growth than expected in 2003 as a result of cooler than normal summer weather and a decline in manufacturing activity in Michigan. In 2004, we have again experienced cooler than normal summer weather. As a result, electric deliveries growth for 2004 is expected to be less than one percent. ELECTRIC BUSINESS UNCERTAINTIES Several electric business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric operations. Such trends and uncertainties include: Environmental - increasing capital expenditures and operating expenses for Clean Air Act compliance, and - potential environmental liabilities arising from various environmental laws and regulations, including potential liability or expenses relating to the Michigan Natural Resources and Environmental Protection Acts and Superfund. Restructuring - response of the MPSC and Michigan legislature to electric industry restructuring issues, - ability to meet peak electric demand requirements at a reasonable cost, without market disruption, - ability to recover any of our net Stranded Costs under the regulatory policies set by the MPSC, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer instead of an electric transmission owner and the impact of the evolving RTO infrastructure. Regulatory - effects of recommendations as a result of the August 14, 2003 blackout, including increased regulatory requirements and new legislation, - regulatory decisions concerning the RCP, CE-19 Consumers Energy Company - effects of the FERC market power test requirements for electric market-based rate authority, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, and - recovery of nuclear decommissioning costs. For additional details, see "Accounting for Nuclear Decommissioning Costs" within this MD&A. Other - effects of commodity fuel prices such as natural gas, oil, and coal, - pending litigation filed by PURPA qualifying facilities, and - other pending litigation. For additional details about these trends or uncertainties, see Note 2, Uncertainties. 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. Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for us. The Title I provisions of the Clean Air Act require significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $802 million. The key assumptions included 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 - allowance for funds used during construction (AFUDC) rate. Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.06 percent. As of September 30, 2004, we have incurred $500 million in capital expenditures to comply with these regulations and anticipate that the remaining $302 million of capital expenditures will be made between 2004 and 2011. These expenditures include installing catalytic reduction technology at some of our coal-fired electric plants. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions allowances for years 2004 through 2009. The cost of the allowances is estimated to average $7 million per year for 2004-2006; the cost will decrease after year 2006 with the installation of plant control technology. The cost of the allowances is accounted for as inventory. The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits 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 plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question. The EPA has proposed a Clean Air Interstate Rule that would require additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. If implemented, this rule would potentially require expenditures equivalent to those efforts in progress to reduce nitrogen oxide emissions as required under the Title I provisions of the Clean Air Act. The rule proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent and nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two alternative sets of rules to reduce emissions of mercury and nickel from coal-fired and CE-20 Consumers Energy Company oil-fired electric plants. Until the proposed environmental rules are finalized, an accurate cost of compliance cannot be determined. Our switch to western coal as fuel has resulted in reduced plant emissions, lower operating costs, and flexibility in meeting future regulatory compliance requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide allowances optimizes our overall cost of regulatory compliance by delaying capital expenditures and minimizing regulatory uncertainty. Western coal has reduced our overall cost of fuel and reduced the impact on us from the recent increases in eastern coal prices. Several bills have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that greenhouse gas emission reduction rules come into effect, such mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sectors. We cannot estimate the potential effect of United States federal or state level greenhouse gas policy on future consolidated results of operations, cash flows, or financial position due to the speculative nature of the policy. We stay abreast of and engage in the greenhouse gas policy developments and will continue to assess and respond to their potential implications on our business operations. In March 2004, the EPA changed the rules that govern generating plant cooling water intake systems. The new rules require significant reduction in fish killed by operating equipment. Some of our facilities will be required to comply by 2006. We are studying the rules to determine the most cost-effective solutions for compliance. For additional details on electric environmental matters, see Note 2, Uncertainties, "Electric Contingencies - Electric Environmental Matters." COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act and other developments will continue to result in increased competition in the electric business. Generally, increased competition reduces profitability and threatens market share for generation services. As of January 1, 2002, the Customer Choice Act allowed all of our electric customers to buy electric generation service from us or from an alternative electric supplier. As a result, alternative electric suppliers for generation services have entered our market. As of October 2004, alternative electric suppliers are providing 877 MW of generation supply to ROA customers. This amount represents 11 percent of our distribution load and an increase of 45 percent compared to October 2003. Based on current trends, we predict load loss by year-end to be in the range of 900 MW to 1,000 MW. However, no assurance can be made that the actual load loss will fall within that range. In July 2004, as a result of legislative hearings, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act. The proposals include: - requiring that rates be based on cost of service, - establishing a defined Stranded Cost calculation method, - allowing customers who stay with or switch to alternative electric suppliers after December 31, 2005 to return to utility services, and requiring them to pay current market rates upon return, - establishing reliability standards that all electric suppliers must follow, - requiring utilities and alternative electric suppliers to maintain a 15 percent power reserve margin, CE-21 Consumers Energy Company - creating a service charge to fund the Low Income and Energy Efficiency Fund, - giving kindergarten through twelfth-grade schools a discount of 10 percent to 20 percent on electric rates, and - authorizing a service charge payable by all customers for meeting Clean Air Act requirements. In September 2004, the Chair of the Senate Technology and Energy Committee formed a workgroup to analyze the merits of the proposed legislation. Workgroup activities have since concluded and their impact on the proposed legislation is still uncertain. In October 2004, a substitute to one of the bills was introduced, but has not yet been adopted by the Michigan Senate. Securitization: In March 2003, we filed an application with the MPSC seeking approval to issue additional Securitization bonds. In June 2003, the MPSC issued a financing order authorizing the issuance of Securitization bonds in the amount of $554 million. We filed for rehearing and clarification on a number of features in the financing order. In October 2004, the MPSC issued an order that reversed the June 2003 financing order and denied our request to issue additional Securitization bonds. Clean Air Act costs, originally included in our Stranded Cost filings, were also part of this Securitization request that was denied. The MPSC order, however, also gave us the option to file for recovery of these costs through a Section 10d(4) Regulatory Asset case, which we filed in October 2004. Stranded Costs: To the extent we experience net Stranded Costs as determined by the MPSC, the Customer Choice Act allows us to recover such costs by collecting a transition surcharge from customers who switch to an alternative electric supplier. We cannot predict whether the Stranded Cost recovery method ultimately adopted by the MPSC will be applied in a manner that will offset fully any associated margin loss. In July 2004, the ALJ issued a Proposal for Decision in our 2002 net Stranded Cost case, which recommended that the MPSC find that we incurred net Stranded Costs of $12 million. This recommendation includes the cost of money through July 2004 and excludes Clean Air Act costs. In July 2004, the MPSC Staff filed a position on our 2003 net Stranded Cost application, which resulted in a Stranded Cost calculation of $52 million. This amount includes the cost of money, but excludes Clean Air Act costs. We cannot predict how the MPSC will rule on these requests for the recovery of Stranded Costs. Therefore, we have not recorded regulatory assets to recognize the future recovery of such costs. Implementation Costs: Following an appeal and remand of initial MPSC orders relating to 1999 implementation costs, the MPSC authorized the recovery of all previously approved implementation costs for the years 1997 through 2001 by surcharges on all customers' bills phased in as rate caps expire. Authorized recoverable implementation costs totaled $88 million. This total includes the cost of money through 2003. Additional carrying costs will be added until collection occurs. For additional information on rate caps, see "Rate Caps" within this section. Our applications for recovery of $7 million of implementation costs for 2002 and $1 million for 2003 are presently pending approval by the MPSC. In September 2004, the ALJ issued a Proposal for Decision recommending full recovery of these costs. Included in the 2002 request is $5 million related to our former participation in the development of the Alliance RTO. Although we believe these implementation costs and associated cost of money are fully recoverable in accordance with the Customer Choice Act, we cannot predict the amount, if any, the MPSC will approve as recoverable. In addition to seeking MPSC approval for these costs, we are pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million for implementation costs related to our former participation in the development of the Alliance RTO. Included in this amount is $5 million pending CE-22 Consumers Energy Company approval by the MPSC as part of the 2002 implementation costs application. The FERC has denied our request for reimbursement and we are appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. We cannot predict the outcome of the appeal process or the amount, if any, we will collect for Alliance RTO development costs. Security Costs: The Customer Choice Act, as amended, allows for recovery of new and enhanced security costs as a result of federal and state regulatory security requirements incurred before January 1, 2006. In August 2004, the MPSC approved a settlement agreement that authorizes full recovery of $25 million in requested security costs over a five-year period beginning in September 2004. The amount includes reasonable and prudent security enhancements through December 31, 2005. All retail customers, except customers of alternative electric suppliers, will pay these charges. As a result, in August 2004, we recorded total approved security costs incurred to date, including the cost of money. As of September 30, 2004, we have recorded $21 million in security costs as a regulatory asset. Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze-cap periods, including the cost of money. In October 2004, we filed an application with the MPSC seeking recovery of $628 million of capital expenditures in excess of depreciation, Clean Air Act costs, and other expenses for the period June 2000 through December 2005. Of the $628 million, $152 million relates to the cost of money. Also included in this application is $74 million of costs that were also incorporated in our Stranded Costs filings. We cannot predict the amount, if any, the MPSC will approve as recoverable. Rate Caps: The Customer Choice Act imposes certain limitations on electric rates that could result in us being unable to collect our full cost of conducting business from electric customers. Such limitations include: - rate caps effective through December 31, 2004 for small commercial and industrial customers, and - rate caps effective through December 31, 2005 for residential customers. As a result, we may be unable to maintain our profit margins in our electric utility business during the rate cap periods. In particular, if we need to purchase power supply from wholesale suppliers while retail rates are capped, the rate restrictions may preclude full recovery of purchased power and associated transmission costs. PSCR: The PSCR process provides for the reconciliation of actual power supply costs with power supply revenues. This process provides for recovery of all reasonable and prudent power supply costs actually incurred by us, including the actual cost for fuel, and purchased and interchange power. In September 2003, we submitted a PSCR filing to the MPSC that reinstates the PSCR process for customers whose rates are no longer frozen or capped as of January 1, 2004. The proposed PSCR charge allows us to recover a portion of our increased power supply costs from large commercial and industrial customers and, subject to the overall rate caps, from other customers. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. In October 2004, the ALJ issued a Proposal for Decision, which recommended approval of our 2004 PSCR factor with minor adjustments. The PSCR factor recommended for approval includes nitrogen oxide emissions allowance costs and requested transmission costs, less a minor adjustment. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $32 million in 2004. CE-23 Consumers Energy Company In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from all other customers. Unless we receive an order from the MPSC, we expect to self-implement this proposed 2005 PSCR charge in January 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings. Special Contracts: We entered into multi-year electric supply contracts with certain industrial and commercial customers. The contracts provide electricity at specially negotiated prices that are at a discount from tariff prices, but above our incremental cost of service. As of October 2004, special contracts for approximately 630 MW of load are in place, most of which are in effect through 2005. Transmission Costs: In May 2002, we sold our electric transmission system for $290 million to MTH. We are currently in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized by approximately $2 million to $3 million. There are multiple proceedings and a proposed rulemaking pending before the FERC regarding transmission pricing mechanisms and standard market design for electric bulk power markets and transmission. The results of these proceedings and proposed rulemakings could affect significantly: - transmission cost trends, - delivered power costs to us, and - delivered power costs to our retail electric customers. As part of the ongoing development of regional transmission systems, the issue of the appropriate level of "through and out" rates has been raised by the FERC in recent orders. Through and out rates occur when a utility purchases electricity that travels through the service territory of other utilities. These utilities charge a rate for the energy going through and out of their service territory. In March 2004, the FERC accepted a settlement whereby, effective December 1, 2004, regional through and out rates for transactions in PJM and MISO would be eliminated. In October 2004, two pricing proposals designed to replace the elimination of through and out rates were submitted to the FERC for approval. One of the pricing proposals could cause us to incur higher transmission costs. We are unable to determine if the FERC will accept either proposal, or will adopt a proposal of its own. The financial impact of such proceedings, rulemaking, and trends are not quantifiable currently. Transmission Market Developments: The MISO is scheduled to begin the Midwest energy market on March 1, 2005. At that time, the MISO will begin providing day-ahead and real-time energy market information for the MISO's participants. These services are anticipated to ensure that load requirements in the region are met reliably and efficiently, to better manage congestion on the grid, and to produce consumer savings through the centralized dispatch of generation throughout the region. The MISO is expected to provide other functions, including long-term regional planning and market monitoring. We are also evaluating whether or not there may be impacts on electric reliability associated with changes in the composition of transmission markets. For example, Commonwealth Edison Company joined the PJM RTO effective May 1, 2004 and American Electric Power Service Corporation joined the PJM RTO effective October 1, 2004. These integrations could create different patterns of flow and power within the Midwest area and could affect adversely our ability to provide reliable service to our customers. CE-24 Consumers Energy Company We are presently evaluating what financial impacts, if any, these market developments will have on our operations. August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid serving parts of the Midwest and the Northeast experienced a significant disturbance that impacted electric service to millions of homes and businesses. As a result, federal and state investigations regarding the cause of the blackout were conducted. These investigations resulted in the NERC and the U.S. and Canadian Power System Outage Task Force releasing electric operations recommendations. Few of the recommendations apply directly to us, since we are not a transmission owner. However, the recommendations could result in increased transmission costs to us and require upgrades to our distribution system. The financial impacts of these recommendations are not quantifiable currently. For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 2, Uncertainties, "Electric Restructuring Matters," and "Electric Rate Matters." PALISADES PLANT OUTAGE: Our Palisades plant is currently undergoing a regularly scheduled refueling outage. In conjunction with this scheduled outage, we have completed inspection of all 54 nuclear reactor vessel head penetrations. Small cracks were identified in the welds on two of the 45 control rod drive penetration nozzles. No external primary coolant system leakage or damage to the reactor head material was noted. Sections of the two penetrations have been removed and replaced. Post-weld testing, restoration of the support attachments, and reactor head installation on the vessel are in progress and are expected to be complete by mid-November. The total outage extension caused by the weld cracks will be approximately four weeks. The plant is expected to return to service by the end of November. For additional details on the Palisades outage, see Note 2, Uncertainties, "Other Electric Uncertainties - Nuclear Matters." UNIT OUTAGE: In June 2004, our 638 MW Karn Unit 4 facility located in Essexville, Michigan experienced a failure on the exciter. The exciter is a device that provides the magnetic field to the main electric generator. We rented a temporary replacement from Detroit Edison. In October 2004, we decided to extend our rental of the temporary replacement until December 2004 during the refueling outage at our Palisades plant, as discussed in "Palisades Plant Outage" within this section. FERC REVISED MARKET POWER TEST: In April 2004, the FERC adopted two new generation market power screen tests and modified measures that can be taken to mitigate market power where it is found. The screens will apply to all initial market-based rate applications and will be reviewed every three years. Based on our filing with the FERC in August 2004, we determined that Consumers passed the established screens, enabling us to sell power at market-based rates. Subsequent to this filing, the FERC staff informally requested a revised market power analysis based on the consolidated figures of Consumers and CMS Energy's Michigan subsidiaries. On October 1, 2004, we submitted the revised market power analysis, which we believe demonstrates that we passed the established screens on a consolidated basis. On October 29, 2004, the FERC staff requested us to provide additional support information and respond to several clarification requests. The FERC also issued similar letters to ten other companies that had made contemporaneous market power filings with the FERC. We are in the process of preparing our response, which is due November 19, 2004. BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of Appeals upheld a lower court decision that requires Detroit Edison to obey a municipal ordinance enacted by the City of Taylor, Michigan. The ordinance requires Detroit Edison to bury a section of its overhead power lines at its own expense. Consumers and other interested parties are considering appeals to the Michigan Supreme Court. Unless overturned by the Michigan Supreme Court, the decision could encourage other municipalities to adopt similar ordinances. This case has potentially broad ramifications for the electric utility and telephone industries in Michigan; however, at this time, we cannot predict the outcome of this matter. CE-25 Consumers Energy Company PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The standards relate to restoration after outages, safety, and customer services. The MPSC order calls for financial penalties in the form of customer credits if the standards for the duration and frequency of outages are not met. We met or exceeded all approved standards for year-end results for both 2002 and 2003. As of September 2004, we are in compliance with the acceptable level of performance. We are a member of an industry coalition that has appealed the customer credit portion of the performance standards to the Michigan Court of Appeals. We cannot predict the likely effects of the financial penalties, if any, nor can we predict the outcome of the appeal. Likewise, we cannot predict our ability to meet the standards in the future or the cost of future compliance. For additional details on performance standards, see Note 2, Uncertainties, "Electric Rate Matters - Performance Standards." GAS BUSINESS OUTLOOK GROWTH: Over the next five years, we expect gas deliveries to grow at an average rate of less than one percent per year. Actual gas deliveries in future periods may be affected by: - fluctuations in weather patterns, - use by independent power producers, - competition in sales and delivery, - Michigan economic conditions, - gas consumption per customer, and - increases in gas commodity prices. In February 2004, we filed an application with the MPSC for a Certificate of Public Convenience and Necessity for the construction of a 25-mile gas transmission pipeline in northern Oakland County. The project is necessary to meet peak load beginning in the winter of 2005 through 2006. If we are unable to construct the pipeline due to local opposition, we will need to pursue more costly alternatives or possibly curtail serving the system's load growth in that area. We are currently involved in settlement discussions with several intervenors. At this time, we cannot predict the outcome of our negotiations. GAS BUSINESS UNCERTAINTIES Several gas business trends or uncertainties may affect our financial results and conditions. These trends or uncertainties could have a material impact on net sales, revenues, or income from gas operations. The trends and uncertainties include: Regulatory - inadequate regulatory response to applications for requested rate increases, - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, and - proposed distribution integrity rules and mandates. Environmental - potential environmental remediation costs at a number of sites, including sites formerly housing manufactured gas plant facilities. CE-26 Consumers Energy Company Other - transmission pipeline integrity mandates, maintenance and remediation costs, and - other pending litigation. GAS BTU CONTENT: We sell gas to retail customers under tariffs approved by the MPSC. These tariffs measure the volume of gas delivered to customers (i.e. mcf). However, we purchase gas for resale on a heating value (i.e. Btu) basis. The Btu content of the gas purchased fluctuates and may result in customers using less gas for the same heating requirement. We fully recover our cost to purchase gas through the approved GCR. However, since the customer may use less gas on a volumetric basis, the revenue from the distribution charge (the non-gas cost portion of the customer bill) could be reduced. This could adversely affect our gas utility earnings. The amount of any possible earnings loss due to fluctuating Btu content in future periods cannot be estimated at this time. GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an order rejecting our filing to assess certain rates for non-physical gas title tracking services we provide. In December 2003, the FERC ruled that no refunds were at issue and we reversed a $4 million reserve related to this matter. In January 2004, three companies filed with the FERC for clarification or rehearing of the FERC's December 2003 order. In April 2004, the FERC issued its Order Granting Clarification. In that order, the FERC indicated that its December 2003 order was in error. It directed us to file within 30 days a fair and equitable title-tracking fee and to make refunds, with interest, to customers based on the difference between the accepted fee and the fee paid. In response to the FERC's April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further Consideration in June 2004. We expect the FERC to issue an order on the merits of this proceeding. We believe that with respect to the FERC jurisdictional transportation, we have not charged any customers title transfer fees, so no refunds are due. At this time, we cannot predict the outcome of this proceeding. GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers for our actual cost of purchased natural gas. The GCR process is designed to allow us to recover all of our prudently incurred gas costs. The MPSC reviews these costs for prudency in an annual reconciliation proceeding. The following table summarizes our GCR reconciliation filings with the MPSC. For additional details, see Note 2, Uncertainties, "Gas Rate Matters - Gas Cost Recovery." Gas Cost Recovery Reconciliation
-------------------------------------------------------------------------------------------------------------------- Net Over GCR Year Date Filed Order Date Recovery Status -------------------------------------------------------------------------------------------------------------------- 2001-2002 June 2002 May 2004 $3 million $2 million has been refunded; $1 million is included in our 2003-2004 GCR reconciliation filing 2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest accrued through March 2003, and an $11 million disallowance settlement agreement 2003-2004 June 2004 Pending $28 million Filing includes the $1 million and $5 million GCR net overrecovery above =====================================================================================================================
Net overrecovery amounts included in the table above include refunds received by us from our suppliers and required by the MPSC to be refunded to our customers. CE-27 Consumers Energy Company GCR plan for year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding. Recent increases in gas prices could cause us to incur costs in excess of what can be recovered pursuant to the current ceiling price. We are permitted to apply to the MPSC to modify the ceiling price, and will do so if necessary. In addition, if actual, prudently incurred costs exceed the ceiling price, the difference can be recovered through the reconciliation proceeding. Our GCR factor for the billing month of November 2004 is $6.55 per mcf. 2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. On December 18, 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes. On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon receipt of a letter signed by the Chairman of Consumers and CMS Energy, which agrees to: - achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached, - make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted, - refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate, - prepare and file annual reports that address certain issues identified in the order, and - file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect). On October 15, 2004, Consumers' and CMS Energy's Chairman filed a letter with the MPSC making the commitments required by the rate order. On October 19, 2004, we filed rehearing petitions with the MPSC, which seek clarification of the method of computing our rate of return on common equity. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003 the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case. On October 14, 2004, the MPSC issued its Opinion and Order in our gas depreciation case. The order restores depreciation rates to the levels that were in effect prior to the issuance of the December 18, 2003 interim gas rate order. The final order further requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to have book depreciation rates restored to the level set forth in the MPSC's prior interim gas rate relief order. GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number CE-28 Consumers Energy Company of sites, including 23 former manufactured gas plant sites. We expect our remaining remedial action costs to be between $37 million and $90 million. We expect to fund most of these costs through insurance proceeds and through the MPSC approved rates charged to our customers. 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. For additional details, see Note 2, Uncertainties, "Gas Contingencies - Gas Environmental Matters." OTHER OUTLOOK CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that applies to utilities and alternative electric suppliers. The code of conduct seeks to prevent financial support, information sharing, and preferential treatment between a utility's regulated and non-regulated services. The new code of conduct is broadly written and could affect our: - retail gas business energy related services, - retail electric business energy related services, - marketing of non-regulated services and equipment to Michigan customers, and - transfer pricing between our departments and affiliates. We appealed the MPSC orders related to the code of conduct and sought a deferral of the orders until the appeal was complete. We also sought waivers available under the code of conduct to continue utility activities that provide approximately $50 million in annual electric and gas revenues. In October 2002, the MPSC denied waivers for three programs including the appliance service plan offered by us, which generated $34 million in gas revenue in 2003. In March 2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code of conduct without modification. We filed an application for leave to appeal with the Michigan Supreme Court, but we cannot predict whether the Michigan Supreme Court will accept the case or the outcome of any appeal. In April 2004, the Michigan Governor signed legislation that allows us to remain in the appliance service business. MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund (net of approximately $16 million of deferred expenses) has not been recognized in year-to-date 2004 earnings. TAX BILL: In October 2004, Congress passed tax legislation, the "American Jobs Creation Act of 2004," which the President signed into law. We are currently studying the tax bill's provisions for its impact, if any, upon Consumers. SARBANES-OXLEY ACT OF 2002: We are in the process of implementing the internal control requirements mandated by the Sarbanes-Oxley Act. Our evaluation and testing of internal controls is continuing, but is incomplete as of the date of this Form 10-Q. We are currently unaware of any material weaknesses in our control over financial reporting. We plan to complete testing and finalize our evaluation in the fourth quarter. Until this is completed, we cannot provide assurance that our internal controls do not contain material weaknesses. CE-29 Consumers Energy Company Our 2004 Form 10-K will contain a report by our management on the effectiveness of our internal controls and a report by Ernst & Young, our Registered Independent Auditors, that attests to and reports on our management's assessment of internal control. These annual reports on internal control are now required by Section 404 of the Sarbanes-Oxley Act for all public companies, effective with our 2004 Form 10-K. 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. Additionally, CMS Energy and Consumers are named as parties in various litigation including a shareholder derivative lawsuit, a securities class action lawsuit, and a class action lawsuit alleging ERISA violations. For additional details regarding these investigations and litigation, see Note 2, Uncertainties. NEW ACCOUNTING STANDARDS FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The FASB issued this Interpretation in January 2003. The objective of the Interpretation is to assist in determining when one party controls another entity in circumstances where a controlling financial interest cannot be properly identified based on voting interests. Entities with this characteristic are considered variable interest entities. The Interpretation requires the party with the controlling financial interest, known as the primary beneficiary, in a variable interest entity to consolidate the entity. In December 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that have not previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No. 46 provided an implementation deferral until the first quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation No. 46 for all entities. We determined that we are the primary beneficiary of both the MCV Partnership and the FMLP. We have a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the MCV Facility, which results in Consumers holding a 35 percent lessor interest in the MCV Facility. Collectively, these interests make us the primary beneficiary of these entities. As such, we consolidated their assets, liabilities, and activities into our financial statements for the first time as of and for the quarter ended March 31, 2004. These partnerships have third-party obligations totaling $581 million at September 30, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.440 billion at September 30, 2004. The creditors of these partnerships do not have recourse to the general credit of CMS Energy. We also determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities have been deconsolidated as of December 31, 2003. Company Obligated Trust Preferred Securities totaling $490 million, that were previously included in mezzanine equity, have been eliminated due to deconsolidation. As a result of the deconsolidation, we reflected $506 million of long-term debt - related parties and reflected an investment in related parties of $16 million. We are not required to restate prior periods for the impact of this accounting change. FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit CE-30 Consumers Energy Company that is actuarially equivalent to Medicare Part D. At December 31, 2003, we elected a one-time deferral of the accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1. The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position, No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position, No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations and postretirement benefit costs should reflect the effects of the Act. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $148 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $17 million for the nine months ended September 30, 2004, and an expected total reduction of $23 million for 2004. Consumers capitalizes a portion of OPEB cost in accordance with regulatory accounting. As such, the remeasurement resulted in a net reduction of OPEB expense of $4 million for the three months ended September 30, 2004, $12 million for the nine months ended September 30, 2004, and an expected total net expense reduction of $16 million for 2004. NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE EITF ISSUE NO. 03-1, THE MEANING OF OTHER THAN TEMPORARY INVESTMENTS: This issue addresses the definition of an other than temporary impairment of certain investments and was scheduled to be effective as of September 30, 2004. The scope of EITF Issue No. 03-1 includes debt and equity securities accounted for under SFAS No. 115, debt and equity securities held by non-profit organizations under SFAS No. 124 and cost method investments under APB Opinion No. 18. The FASB issued a final FASB Staff Position, FSP EITF Issue 03-1-1 deferring portions of EITF Issue No. 03-1 relating to guidance on such matters as to what constitutes a minor impairment and the determination of "other than temporary." The deferral extends until the Board issues a final FSP 03-1-a defining the effective date and amending EITF Issue No. 03-1 as it is currently written. The FASB expects to issue the FASB Staff Position in November. The deferral does not apply to the disclosure requirements of EITF Issue No. 03-1, which are required in our annual financial statements. We do not expect this issue to have an impact on our results of operations when it becomes effective. EITF ISSUE NO. 04-10, APPLYING PARAGRAPH 19 OF SFAS NO. 131, DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, IN DETERMINING WHETHER TO AGGREGATE OPERATING SEGMENTS THAT DO NOT MEET THE QUANTITATIVE THRESHOLDS: This issue addresses how to apply the operating segment aggregation criteria in SFAS No. 131. At their September 2004 meeting, the EITF reached consensus on this issue. The EITF concluded that operating segments that do not meet the quantitative thresholds established in SFAS No. 131 could be aggregated only if aggregation is consistent with the objective and basic principles of Statement 131 and the segments have similar economic characteristics. The consensus will be effective as of December 31, 2004. We do not expect this issue to have an impact on our segment reporting under SFAS No. 131 when it becomes effective. CE-31 Consumers Energy Company (This page intentionally left blank) CE-32 CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 2004 2003 2004 2003 ------------------------------------------------------------------------------------------- In Millions OPERATING REVENUE $ 885 $ 879 $ 3,355 $ 3,223 EARNINGS (LOSS) FROM EQUITY METHOD INVESTEES 1 (3) 1 31 OPERATING EXPENSES Fuel for electric generation 194 89 518 245 Purchased and interchange power 71 103 171 260 Purchased power - related parties 18 131 49 383 Cost of gas sold 89 90 947 793 Cost of gas sold - related parties - 2 1 27 Other operating expenses 181 178 529 505 Maintenance 56 41 163 149 Depreciation, depletion and amortization 104 80 335 275 General taxes 51 47 163 130 -------------------------------------- 764 761 2,876 2,767 ------------------------------------------------------------------------------------------- OPERATING INCOME 122 115 480 487 OTHER INCOME (DEDUCTIONS) Accretion expense (1) (1) (3) (5) Interest and dividends 4 1 11 6 Gain on asset sales, net 1 - 1 - Other income 13 2 35 6 Other expense (2) (1) (4) (15) -------------------------------------- 15 1 40 (8) ------------------------------------------------------------------------------------------- INTEREST CHARGES Interest on long-term debt 70 51 215 144 Interest on long-term debt - related parties 11 - 33 - Other interest 4 2 11 10 Capitalized interest (2) (2) (5) (7) -------------------------------------- 83 51 254 147 ------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS 54 65 266 332 INCOME TAXES 19 21 91 126 MINORITY INTERESTS 1 - 12 - -------------------------------------- NET INCOME 34 44 163 206 PREFERRED STOCK DIVIDENDS - - 1 1 PREFERRED SECURITIES DISTRIBUTIONS - 11 - 33 -------------------------------------- NET INCOME AVAILABLE TO COMMON STOCKHOLDER $ 34 $ 33 $ 162 $ 172 ===========================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-33 CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30 2004 2003 ----------------------------------------------------------------------------------------------- In Millions CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 163 $ 206 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization (includes nuclear decommissioning of $4 and $4, respectively) 335 275 Gain on sale of assets (1) - Capital lease and other amortization 20 20 Loss on CMS Energy stock - 12 Distributions from related parties less than earnings - 14 Pension contribution - (172) Changes in assets and liabilities: Decrease (increase) in accounts receivable and accrued revenue (1) 156 Increase (decrease) in accounts payable 27 (26) Decrease in accrued expenses (130) (132) Increase in inventories (273) (335) Deferred income taxes and investment tax credit 91 72 Decrease in other current and non-current assets 54 96 Increase (decrease) in other current and non-current liabilities 45 (43) ----------------- Net cash provided by operating activities $ 330 $ 143 ----------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excludes assets placed under capital lease) $(368) $ (306) Cost to retire property (53) (52) Restricted cash on hand (Note 1) (34) (1) Investments in Electric Restructuring Implementation Plan (5) (5) Investments in nuclear decommissioning trust funds (4) (4) Proceeds from nuclear decommissioning trust funds 35 26 Maturity of MCV restricted investment securities held-to-maturity 592 - Purchase of MCV restricted investment securities held-to-maturity (592) - Cash proceeds from sale of assets 2 15 ---------------- Net cash used in investing activities $(427) $ (327) ----------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of long term debt $ 817 $ 1,543 Retirement of long-term debt (727) (780) Payment of common stock dividends (187) (162) Preferred securities distributions - (33) Payment of preferred stock dividends (2) (1) Payment of capital and finance lease obligations (41) (10) Decrease in notes payable, net - (457) Stockholder's contribution, net 150 - ----------------- Net cash provided by financing activities $ 10 $ 100 ----------------------------------------------------------------------------------------------- Net Decrease in Cash and Cash Equivalents $ (87) $ (84) Cash and Cash Equivalents from Effect of Revised FASB Interpretation No. 46 Consolidation 174 - Cash and Cash Equivalents, Beginning of Period 46 244 ---------------- Cash and Cash Equivalents, End of Period $ 133 $ 160 ===============================================================================================
CE-34 OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
In Millions September 30 Nine Months Ended 2004 2003 ------------------------------------------------------------------- CASH TRANSACTIONS Interest paid (net of amounts capitalized) $ 237 $156 Income taxes paid 7 32 OPEB cash contribution 47 53 NON-CASH TRANSACTIONS Other assets placed under capital lease 2 11 ==================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-35 CONSUMERS ENERGY COMPANY CONSOLIDATED BALANCE SHEETS ASSETS
SEPTEMBER 30 SEPTEMBER 30 2004 DECEMBER 31 2003 (UNAUDITED) 2003 (UNAUDITED) ----------------------------------------------------------------------------------------------------------------------------- In Millions PLANT (AT ORIGINAL COST) Electric $ 7,860 $ 7,600 $ 7,583 Gas 2,929 2,875 2,841 Other 2,523 15 15 ---------------------------------------------- 13,312 10,490 10,439 Less accumulated depreciation, depletion and amortization 5,589 4,417 4,403 ---------------------------------------------- 7,723 6,073 6,036 Construction work-in-progress 405 375 359 ---------------------------------------------- 8,128 6,448 6,395 ----------------------------------------------------------------------------------------------------------------------------- INVESTMENTS Stock of affiliates 23 20 17 First Midland Limited Partnership - 224 222 Midland Cogeneration Venture Limited Partnership - 419 404 Other 19 18 2 ---------------------------------------------- 42 681 645 ----------------------------------------------------------------------------------------------------------------------------- CURRENT ASSETS Cash and cash equivalents at cost, which approximates market 133 46 160 Restricted cash 52 18 19 Accounts receivable, notes receivable and accrued revenue, less allowances of $8, $8 and $7 respectively 289 257 81 Accounts receivable - related parties 12 4 7 Inventories at average cost Gas in underground storage 995 739 813 Materials and supplies 71 70 72 Generating plant fuel stock 77 41 44 Deferred property taxes 111 143 88 Regulatory assets 19 19 19 Derivative instruments 143 2 2 Other 79 78 92 ---------------------------------------------- 1,981 1,417 1,397 ----------------------------------------------------------------------------------------------------------------------------- NON-CURRENT ASSETS Regulatory Assets Securitized costs 616 648 659 Postretirement benefits 145 162 168 Abandoned Midland Project 10 10 10 Other 368 266 257 Nuclear decommissioning trust funds 551 575 553 Prepaid pension costs 349 364 - Other 311 174 147 ---------------------------------------------- 2,350 2,199 1,794 ---------------------------------------------- TOTAL ASSETS $ 12,501 $ 10,745 $ 10,231 =============================================================================================================================
CE-36 STOCKHOLDER'S EQUITY AND LIABILITIES
SEPTEMBER 30 SEPTEMBER 30 2004 DECEMBER 31 2003 (UNAUDITED) 2003 (UNAUDITED) ---------------------------------------------------------------------------------------------------------------------- In Millions CAPITALIZATION Common stockholder's equity Common stock, authorized 125.0 shares; outstanding 84.1 shares for all periods $ 841 $ 841 $ 841 Paid-in capital 832 682 682 Accumulated other comprehensive income (loss) 38 17 (191) Retained earnings since December 31, 1992 496 521 555 --------------------------------------- 2,207 2,061 1,887 Preferred stock 44 44 44 Company-obligated mandatorily redeemable preferred securities of subsidiaries - - 490 Long-term debt 3,986 3,583 3,531 Long-term debt - related parties 506 506 - Non-current portion of capital and finance lease obligations 318 58 116 --------------------------------------- 7,061 6,252 6,068 --------------------------------------------------------------------------------------------------------------- MINORITY INTERESTS 675 - - --------------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Current portion of long-term debt, capital leases and finance leases 177 38 39 Notes payable - related parties 200 200 - Accounts payable 253 200 245 Accrued taxes 61 209 84 Accounts payable - related parties 12 75 65 Current portion of purchase power contract 6 27 26 Deferred income taxes 30 33 23 Other 300 185 168 --------------------------------------- 1,039 967 650 --------------------------------------------------------------------------------------------------------------- NON-CURRENT LIABILITIES Deferred income taxes 1,328 1,233 1,009 Regulatory Liabilities Cost of removal 1,026 983 962 Income taxes, net 326 312 309 Other 160 172 152 Postretirement benefits 172 190 431 Asset retirement obligations 436 358 362 Deferred investment tax credit 81 85 86 Power purchase agreement - MCV Partnership - - 8 Other 197 193 194 --------------------------------------- 3,726 3,526 3,513 --------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES (Notes 1, 2, and 5) TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES $ 12,501 $ 10,745 $ 10,231 ===============================================================================================================
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-37 CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
Three Months Ended Nine Months Ended SEPTEMBER 30 2004 2003 2004 2003 ------------------------------------------------------------------------------------------------------------------- In Millions COMMON STOCK At beginning and end of period (a) $ 841 $ 841 $ 841 $ 841 ----------------------------------------------------------------------------------------------------------------- OTHER PAID-IN CAPITAL At beginning of period 682 682 682 682 Stockholder's contribution 150 - 150 - ---------------------------------------- At end of period 832 682 832 682 -------------------------------------------------------------------------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Minimum Pension Liability At beginning of period - (202) - (185) Minimum liability pension adjustments (b) (1) - (1) (17) ---------------------------------------- At end of period (1) (202) (1) (202) ---------------------------------------- Investments At beginning of period 10 8 9 1 Unrealized gain (loss) on investments (c) - (2) 1 5 ---------------------------------------- At end of period 10 6 10 6 ---------------------------------------- Derivative Instruments At beginning of period 16 11 8 5 Unrealized gain (loss) on derivative instruments (c) 14 (4) 27 9 Reclassification adjustments included in consolidated net (loss) (c) (1) (2) (6) (9) ---------------------------------------- At end of period 29 5 29 5 ------------------------------------------------------------------------------------------------------------------- Total Accumulated Other Comprehensive Income (Loss) 38 (191) 38 (191) -------------------------------------------------------------------------------------------------------------------- RETAINED EARNINGS At beginning of period 544 522 521 545 Net Income 34 44 163 206 Cash dividends declared - Common Stock (82) - (187) (162) Cash dividends declared - Preferred Stock - - (1) (1) Preferred securities distributions - (11) - (33) ---------------------------------------- At end of period 496 555 496 555 -------------------------------------------------------------------------------------------------------------------- TOTAL COMMON STOCKHOLDER'S EQUITY $ 2,207 $ 1,887 $ 2,207 $ 1,887 ===================================================================================================================
CE-38
THREE MONTHS ENDED NINE MONTHS ENDED September 30 2004 2003 2004 2003 ------------------------------------------------------------------------------ --------- --------- --------- --------- (a) Number of shares of common stock outstanding was 84,108,789 for all periods presented. (b) Because of the significant change in the makeup of the pension plan due to the sale of Panhandle, SFAS No. 87 required a remeasurement of the obligation at the date of sale. The remeasurement resulted in an additional charge to Accumulated Other Comprehensive Income of approximately $27 million ($17 million, net of tax) in 2003 as a result of the increase in the additional minimum pension liability. (c) Disclosure of Comprehensive Income: Minimum pension liability adjustments, net of tax (tax benefit) of $(1), $-, $(1) and $-, respectively (b) $ (1) $ - $ (1) $ (17) Investments Unrealized gain (loss) on investments, net of tax (tax benefit) of $-, $-, $1 and $(3), respectively - (2) 1 5 Derivative Instruments Unrealized gain (loss) on derivative instruments, net of tax (tax benefit) of $7, $2, $14, and $(4), respectively 14 (4) 27 9 Reclassification adjustments included in consolidated net income, net of tax (tax benefit) of $(1), $1, $(3) and $5, respectively (1) (2) (6) (9) Net income 34 44 163 206 -------- --------- --------- -------- Total Comprehensive Income $ 46 $ 36 $ 184 $ 194 ======== ========= ========= ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-39 Consumers Energy Company (This page intentionally left blank) CE-40 Consumers Energy Company CONSUMERS ENERGY COMPANY CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) These interim Consolidated Financial Statements have been prepared by Consumers in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. As such, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted. Certain prior year amounts have been reclassified to conform to the presentation in the current year. In management's opinion, the unaudited information contained in this report reflects all adjustments of a normal recurring nature necessary to assure the fair presentation of financial position, results of operations and cash flows for the periods presented. The Condensed Notes to Consolidated Financial Statements and the related Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements contained in the Consumers' Form 10-K for the year ended December 31, 2003. Due to the seasonal nature of Consumers' operations, the results as presented for this interim period are not necessarily indicative of results to be achieved for the fiscal year. 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 that provides service to customers in Michigan's Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers, the largest segment of which is the automotive industry. 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 Revised FASB Interpretation No. 46. The primary beneficiary of a variable interest entity is the party that absorbs or receives a majority of the entity's expected losses or expected residual returns or both as a result of holding variable interests, which are ownership, contractual, or other economic interests. In 2004, we consolidated the MCV Partnership and the FMLP in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 7, Implementation of New Accounting Standards. 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. Intercompany transactions and balances have been eliminated. USE OF ESTIMATES: We prepare our financial statements in conformity with accounting principles generally accepted in the United States. We are required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates. We are required to record estimated liabilities in the 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. We have used this accounting principle to record estimated liabilities as discussed in Note 2, Uncertainties. CE-41 Consumers Energy Company REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the storage of natural gas when services are provided. Sales taxes are recorded as liabilities and are not included in revenues. CAPITALIZED INTEREST: We are required to 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 that is incurred. Our regulated businesses are permitted to capitalize an allowance for funds used during construction on regulated construction projects and to include such amounts in plant in service. CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an original maturity of three months or less are considered cash equivalents. At September 30, 2004, our restricted cash on hand was $52 million. Restricted cash primarily includes cash dedicated for repayment of bonds. It is classified as a current asset as the payments on the related bonds occur within one year. FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities using SFAS No. 115. Debt and equity securities can be classified into one of three categories: held-to-maturity, trading, or available-for-sale. Our debt securities are classified as held-to-maturity securities and are reported at cost. Our investments in equity securities are classified as available-for-sale securities and are reported at fair value determined from quoted market prices. Any unrealized gains or losses resulting from changes in fair value are reported in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses resulting from changes in the fair value of our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. For additional details regarding financial instruments, see Note 4, Financial and Derivative Instruments. 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 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. As of September 30, 2004, we have recorded a liability to the DOE for $140 million, including interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. The amount of this liability, excluding a portion of interest, was recovered through electric rates. For additional details on disposal of spent nuclear fuel, see Note 2, Uncertainties, "Other Electric Uncertainties - Nuclear Matters." OTHER INCOME AND OTHER EXPENSE: The following tables show the components of Other income and Other expense:
In Millions ---------------------------------------------------------------------------------------------------------------- Three Months Ended Nine Months Ended ------------------------------------------------ September 30 2004 2003 2004 2003 ---------------------------------------------------------------------------------------------------------------- Other income PA 141 Return on Capital Expenditures $ 10 $ - $ 28 $ - Electric restructuring return 2 1 5 4 All other 1 1 2 2 ---------------------------------------------------------------------------------------------------------------- Total other income $ 13 $ 2 $ 35 $ 6 ================================================================================================================
CE-42 Consumers Energy Company
In Millions ------------------------------------------------------------------------------------------------------------------ Three Months Ended Nine Months Ended ------------------------------------------------- September 30 2004 2003 2004 2003 ------------------------------------------------------------------------------------------------------------------ Other expense Loss on CMS Energy stock $ -- $ -- $ -- $ (12) Civic and political expenditures (1) -- (2) (1) All other (1) (1) (2) (2) ------------------------------------------------------------------------------------------------------------------ Total other expense $ (2) $ (1) $ (4) $ (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, the original cost is charged to accumulated depreciation. The cost of removal, less salvage, is recorded as a regulatory liability. For additional details, see Note 6, Asset Retirement Obligations. An allowance for funds used during construction is capitalized on regulated construction projects. With respect to the retirement or disposal of non-regulated assets, the resulting gains or losses are recognized in income. RECLASSIFICATIONS: Certain prior year amounts have been reclassified for comparative purposes. These reclassifications did not affect consolidated net income for the years presented. 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 available to the common stockholder of each segment. We operate principally in two segments: 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 the segments are the same as we describe in this Note. Our 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 available to common stockholder by segment. The "Other" segment includes our consolidated special purpose entity for the sale of trade receivables and our variable interest entities. The following table shows our financial information by reportable segment: CE-43 Consumers Energy Company
In Millions --------------------------------------------------------------------------------------------------------------- Three Months Ended Nine Months Ended ------------------------------------------------------ September 30 2004 2003 2004 2003 --------------------------------------------------------------------------------------------------------------- Operating revenue Electric $ 704 $ 714 $ 1,947 $ 1,970 Gas 171 164 1,376 1,252 Other 10 1 32 1 --------------------------------------------------------------------------------------------------------------- Total Operating Revenue $ 885 $ 879 $ 3,355 $ 3,223 =============================================================================================================== Net income available to common stockholder Electric $ 49 $ 59 $ 124 $ 145 Gas (11) (19) 46 40 Other (4) (7) (8) (13) --------------------------------------------------------------------------------------------------------------- Total Net Income $ 34 $ 33 $ 162 $ 172 ===============================================================================================================
In Millions --------------------------------------------------------------------------------------------------------------- September 30 2004 2003 --------------------------------------------------------------------------------------------------------------- Assets Electric (a) $ 6,972 $ 6,551 Gas (a) 3,230 2,952 Other 2,299 728 ---------------------------------------------------------------------------------------------------------------- Total Assets $ 12,501 $ 10,231 ===============================================================================================================
(a) Amounts include a portion of our other common assets attributable to both the electric and gas utility businesses. UTILITY REGULATION: We account for the effects of regulation based on the regulated utility accounting standard SFAS No. 71. As a result, the actions of regulators affect when we recognize revenues, expenses, assets, and liabilities. SFAS No. 144 imposes strict criteria for retention of regulatory-created assets by requiring that such assets be probable of future recovery at each balance sheet date. Management believes these assets are probable of future recovery. 2: UNCERTAINTIES Several business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric and gas operations. Such trends and uncertainties include: CE-44 Consumers Energy Company Environmental - increased capital expenditures and operating expenses for Clean Air Act compliance, and - potential environmental liabilities arising from various environmental laws and regulations, including potential liability or expense relating to the Michigan Natural Resources and Environmental Protection Acts, Superfund, and at former manufactured gas plant facilities. Restructuring - response of the MPSC and Michigan legislature to electric industry restructuring issues, - ability to meet peak electric demand requirements at a reasonable cost, without market disruption, - ability to recover any of our net Stranded Costs under the regulatory policies set by the MPSC, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer, instead of an electric transmission owner and the impact of the evolving RTO infrastructure. Regulatory - recovery of nuclear decommissioning costs, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, - regulatory decisions concerning the RCP, - inadequate regulatory response to applications for requested rate increases, - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, and - proposed distribution integrity rules and mandates. Other - pending litigation regarding PURPA qualifying facilities, - transmission pipeline integrity mandates, maintenance and remediation costs, and - other pending litigation. SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading transactions by CMS MST, CMS Energy's Board of Directors established a Special Committee to investigate matters surrounding the transactions and retained outside counsel to assist in the investigation. The Special Committee completed its investigation and reported its findings to the Board of Directors in October 2002. The Special Committee concluded, based on an extensive investigation, that the round-trip trades were undertaken to raise CMS MST's profile as an energy marketer with the goal of enhancing its ability to promote its services to new customers. The Special Committee found no effort to manipulate the price of CMS Energy Common Stock or affect energy prices. The Special Committee also made recommendations designed to prevent any recurrence of this practice. Previously, CMS Energy terminated its speculative trading business and revised its risk management policy. The Board of Directors adopted, and CMS Energy has implemented the recommendations of the Special Committee. CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading. 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 nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. CE-45 Consumers Energy Company SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of securities class action complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates. The complaints were filed as purported class actions in the United States District Court for the Eastern District of Michigan, by shareholders who allege that they purchased CMS Energy's securities during a purported class period. The cases were consolidated into a single lawsuit and an amended and consolidated class action complaint was filed on May 1, 2003. The consolidated complaint contains a purported class period beginning on May 1, 2000 and running through March 31, 2003. It 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. The judge issued an opinion and order dated March 31, 2004 in connection with various pending motions, including plaintiffs' motion to amend the complaint and the motions to dismiss the complaint filed by CMS Energy, Consumers, and other defendants. The judge directed plaintiffs to file an amended complaint under seal and ordered an expedited hearing on the motion to amend, which was held on May 12, 2004. At the hearing, the judge ordered plaintiffs to file a Second Amended Consolidated Class Action complaint deleting Counts III and IV relating to purchasers of CMS PEPS, which the judge ordered dismissed with prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS Energy, Consumers, and the individual defendants filed new motions to dismiss on June 21, 2004. A hearing on those motions occurred on August 2, 2004 and the judge has taken the matter under advisement. CMS Energy, Consumers, and the individual defendants will defend themselves vigorously but cannot predict the outcome of this litigation. ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST, and certain named and unnamed officers and directors, in two lawsuits brought as purported class actions on behalf of participants and beneficiaries of the CMS Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July 2002 in United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended consolidated complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge issued an opinion and order dated March 31, 2004 in connection with the motions to dismiss filed by CMS Energy, Consumers, and the individuals. The judge dismissed certain of the amended counts in the plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims in the complaint. CMS Energy, Consumers, and the individual defendants filed answers to the amended complaint on May 14, 2004. A trial date has not been set, but is expected to be no earlier than late in 2005. CMS Energy and Consumers will defend themselves vigorously but cannot predict the outcome of this litigation. 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. Clean Air: The EPA and the state regulations require us to make significant capital expenditures estimated to be $802 million. As of September 30, 2004, we have incurred $500 million in capital expenditures to comply with the EPA regulations and anticipate that the remaining $302 million of capital expenditures will be made between 2004 and 2011. These expenditures include installing catalytic reduction technology at some of our coal-fired electric plants. Based on the Customer Choice Act, beginning January 2004, an annual return of and on these types of capital expenditures, to the extent CE-46 Consumers Energy Company they are above depreciation levels, is expected to be recoverable from customers, subject to the MPSC prudency hearing. The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits 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 plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions allowances for years 2004 through 2009. The cost of the allowances is estimated to average $7 million per year for 2004-2006; the cost will decrease after year 2006 with the installation of plant control technology. The cost of the allowances is accounted for as inventory. The allowance inventory is expensed as the coal-fired electric plants generate electricity. The price for nitrogen oxide emissions allowances is volatile and could change substantially. The EPA has proposed a Clean Air Interstate Rule that would require additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. If implemented, this rule would potentially require expenditures equivalent to those efforts in progress to reduce nitrogen oxide emissions as required under the Title I provisions of the Clean Air Act. The rule proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent and nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two alternative sets of rules to reduce emissions of mercury and nickel from coal-fired and oil-fired electric plants. Until the proposed environmental rules are finalized, an accurate cost of compliance cannot be determined. Our switch to western coal as fuel has resulted in reduced plant emissions, lower operating costs, and flexibility in meeting future regulatory compliance requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide allowances optimizes our overall cost of regulatory compliance by delaying capital expenditures and minimizing regulatory uncertainty. Western coal has reduced our overall cost of fuel and reduced the impact on us from the recent increases in eastern coal prices. Several bills have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that greenhouse gas emission reduction rules come into effect, such mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sectors. We cannot estimate the potential effect of United States federal or state level greenhouse gas policy on future consolidated results of operations, cash flows, or financial position due to the speculative nature of the policy. We stay abreast of and engage in the greenhouse gas policy developments, and will continue to assess and respond to their potential implications on our business operations. Water: In March 2004, the EPA changed the rules that govern generating plant cooling water intake systems. The new rules require significant reduction in fish killed by operating equipment. Some of our facilities will be required to comply by 2006. We are studying the rules to determine the most cost-effective solutions for compliance. CE-47 Consumers Energy Company 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 past experience, we estimate that our share of the total liability for the known Superfund sites will be between $1 million and $9 million. As of September 30, 2004, we have recorded a liability for the minimum amount of our estimated Superfund liability. In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at the Ludington Pumped Storage facility. We removed and replaced part of the PCB material. We have proposed a plan to deal with the remaining materials and are awaiting a response from the EPA. LITIGATION: In October 2003, a group of eight PURPA qualifying facilities selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit alleges that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. More specifically, the lawsuit alleges that we should be basing the energy charge calculation on the cost of more expensive eastern coal, rather than on the cost of the coal actually burned by us for use in our coal-fired generating plants. We believe we have been performing the calculation in the manner prescribed by the power purchase agreements, and have filed a request with the MPSC (as a supplement to the 2004 PSCR plan case) that asks the MPSC to review this issue and to confirm that our method of performing the calculation is correct. We filed a motion to dismiss the lawsuit in the Ingham County Circuit Court due to the pending request at the MPSC concerning the PSCR plan case. In February 2004, the judge ruled on the motion and deferred to the primary jurisdiction of the MPSC. This ruling resulted in a dismissal of the circuit court case without prejudice. In October 2004, the ALJ in the PSCR plan case issued a Proposal for Decision concluding that we have been correctly administering the energy charge calculation methodology that is specified in the power purchase agreements. Although only eight qualifying facilities have raised the issue, the same energy charge methodology is used in the PPA with the MCV Partnership and in approximately 20 additional power purchase agreements with us, representing a total of 1,670 MW of electric capacity. The eight plaintiff qualifying facilities have appealed the dismissal of the circuit court case to the Michigan Court of Appeals. We cannot predict the outcome of this matter. ELECTRIC RESTRUCTURING MATTERS ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, the Michigan legislature passed electric utility restructuring legislation known as the Customer Choice Act. This Act: - allows all customers to choose their electric generation supplier effective January 1, 2002, - provides for a one-time five percent residential electric rate reduction, - froze all electric rates through December 31, 2003, and established a rate cap for residential customers through at least December 31, 2005, and a rate cap for small commercial and industrial customers through at least December 31, 2004, - allows deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and during the rate freeze-cap period, including the cost of money, CE-48 Consumers Energy Company - allows for the use of Securitization bonds to refinance qualified costs, - allows recovery of net Stranded Costs and implementation costs incurred as a result of the passage of the Act, - requires Michigan utilities to join a FERC-approved RTO or sell their interest in transmission facilities to an independent transmission owner, - requires Consumers, Detroit Edison, and AEP to expand jointly their available transmission capability by at least 2,000 MW, and - establishes a market power supply test that, if not met, may require transferring control of generation resources in excess of that required to serve retail sales requirements. The following summarizes our status under the last three provisions of the Customer Choice Act. First, we chose to sell our interest in our transmission facilities to an independent transmission owner to comply with the Customer Choice Act. For additional details regarding the sale of the transmission facility, see "Transmission Sale" within this Note. Second, in July 2002, the MPSC issued an order approving our plan to achieve the increased transmission capacity required under the Customer Choice Act. We have completed the transmission capacity projects identified in the plan and have submitted verification of this fact to the MPSC. We believe we are in full compliance. Lastly, in September 2003, the MPSC issued an order finding that we are in compliance with the market power supply test set forth in the Customer Choice Act. ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms, and conditions under which retail customers are permitted to choose an electric supplier. These revised tariffs allow ROA customers, upon as little as 30 days notice to us, to return to our generation service at current tariff rates. If any class of customers' (residential, commercial, or industrial) ROA load reaches ten percent of our total load for that class of customers, then returning ROA customers for that class must give 60 days notice to return to our generation service at current tariff rates. However, we may not have capacity available to serve returning ROA customers that is sufficient or reasonably priced. As a result, we may be forced to purchase electricity on the spot market at higher prices than we can recover from our customers during the rate cap periods. We cannot predict the total amount of electric supply load that may be lost to alternative electric suppliers. As of October 2004, alternative electric suppliers are providing 877 MW of load. This amount represents 11 percent of the total distribution load and an increase of 45 percent compared to October 2003. ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric restructuring proceedings. They are: - Securitization, - Stranded Costs, - implementation costs, - security costs, - Section 10d(4) Regulatory Assets, and - transmission rates. CE-49 Consumers Energy Company The following chart summarizes our filings with the MPSC. For additional details related to these proceedings, see the related sections within this Note.
----------------------------------------------------------------------------------------------------------------- Year(s) Years Requested Proceeding Filed Covered Amount Status ----------------------------------------------------------------------------------------------------------------- Securitization 2003 N/A $1.083 billion MPSC denied our request to issue additional Securitization bonds. Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced zero Stranded Costs for 2000 through 2001, which we are appealing. Filings for 2002 and 2003 in the amount of $116 million are pending MPSC approval. Implementation Costs 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the years 1997-2001, plus $20 million for the cost of money through 2003. Implementation cost filings for 2002 and 2003 in the amount of $8 million, which includes the cost of money through 2003, are still pending MPSC approval. Security Costs 2004 2001-2005 $25 million MPSC approved the $25 million requested for recovery. As of September 30, 2004, we have recorded $21 million of costs incurred as a regulatory asset. Section 10d(4) 2004 2001-2005 $628 million Filed with the MPSC in October 2004. Regulatory Assets ===================================================================================================================
(a) Amount includes the cost of money through the year in which we expected to receive recovery from the MPSC and assumes recovery of Clean Air Act costs through the Section 10d(4) Regulatory Asset case. If Clean Air Act costs are not recovered through the Section 10d(4) Regulatory Asset case, Stranded Costs requested would total $304 million. (b) Amount includes the cost of money through the year prior to the year filed. Securitization: The Customer Choice Act allows for the use of Securitization bonds to refinance certain qualified costs. Since Securitization involves issuing bonds secured by a revenue stream from rates collected directly from customers to service the bonds, Securitization bonds typically have a higher credit rating than conventional utility corporate financing. In 2000 and 2001, the MPSC issued orders authorizing us to issue Securitization bonds. We issued our first Securitization bonds in late 2001. Securitization resulted in: CE-50 Consumers Energy Company - lower interest costs, and - longer amortization periods for the securitized assets. We will recover the repayment of principal, interest, and other expenses relating to the bond issuance through a Securitization charge and a tax charge that began in December 2001. These charges are subject to an annual true up until one year before the last scheduled bond maturity date, and no more than quarterly thereafter. The December 2004 true up filed with the MPSC in October 2004, is expected to modify the total Securitization and related tax charges from 1.718 mills per kWh to 1.735 mills per kWh. There will be no impact on customer bills from Securitization for most of our electric customers until the Customer Choice Act rate cap period expires, and an electric rate case is processed. Securitization charge collections, $38 million for the nine months ended September 30, 2004, and $37 million for the nine months ended September 30, 2003, are remitted to a trustee. Securitization charge collections are restricted to the repayment of the principal and interest on the Securitization bonds and payment of the ongoing expenses of Consumers Funding. Consumers Funding is legally separate from Consumers. The assets and income of Consumers Funding, including the securitized property, are not available to creditors of Consumers or CMS Energy. In March 2003, we filed an application with the MPSC seeking approval to issue additional Securitization bonds. In June 2003, the MPSC issued a financing order authorizing the issuance of Securitization bonds in the amount of $554 million. We filed for rehearing and clarification on a number of features in the financing order. In October 2004, the MPSC issued an order that reversed the June 2003 financing order and denied our request to issue additional Securitization bonds. Clean Air Act costs, originally included in our Stranded Cost filings, were also part of this Securitization request that was denied. The MPSC order, however, also gave us the option to file for recovery of these costs through a Section 10d(4) Regulatory Asset case, which we filed in October 2004. Stranded Costs: The Customer Choice Act allows electric utilities to recover their net Stranded Costs, without defining the term. In December 2001, the MPSC Staff recommended a methodology, which calculated net Stranded Costs as the shortfall between: - the revenue required to cover the costs associated with fixed generation assets and capacity payments associated with purchase power agreements, and - the revenues received from customers under existing rates available to cover the revenue requirement. The MPSC authorizes us to use deferred accounting to recognize the future recovery of costs determined to be stranded. According to the MPSC, net Stranded Costs are to be recovered from ROA customers through a Stranded Cost recovery charge. However, the MPSC has not yet approved such a charge. The MPSC has declined to resolve numerous issues regarding the net Stranded Cost recovery methodology in a way that would allow a reliable prediction of the level of Stranded Costs. As a result, we have not recorded regulatory assets to recognize the future recovery of such costs. CE-51 Consumers Energy Company The following table outlines our applications filed with the MPSC and the status of recovery for these costs:
In Millions ------------------------------------------------------------------------------------------------------------------ Requested, without recovery of Requested, with recovery of Clean Air Act costs through the Clean Air Act costs through the approval of Section 10d(4) approval of Section 10d(4) MPSC ordered Year Year Regulatory Assets, including cost Regulatory Assets, including recoverable Filed Incurred of money cost of money amount ------------------------------------------------------------------------------------------------------------------ 2002 2000 $ 26 $12 $ - 2002 2001 46 9 - 2003 2002 104 47 Pending 2004 2003 128 69 Pending ==================================================================================================================
We are currently in the process of appealing the MPSC orders regarding Stranded Costs for 2000 and 2001 with the Michigan Court of Appeals and the Michigan Supreme Court. In June 2004, the MPSC conducted hearings for our 2002 Stranded Cost application. In July 2004, the ALJ issued a Proposal for Decision in our 2002 net Stranded Cost case, which recommended that the MPSC find that we incurred net Stranded Costs of $12 million. This recommendation includes the cost of money through July 2004 and excludes Clean Air Act costs. Hearings for our 2003 Stranded Cost application were conducted in August 2004. The MPSC Staff issued a position on our 2003 net Stranded Cost application, which resulted in a Stranded Cost calculation of $52 million. This amount includes the cost of money, but excludes Clean Air Act costs. We cannot predict how the MPSC will rule on our requests for recoverability of 2002 and 2003 Stranded Costs or whether the MPSC will adopt a Stranded Cost recovery method that will offset fully any associated margin loss from ROA. Implementation Costs: The Customer Choice Act allows electric utilities to recover their implementation costs. The following table outlines our applications filed with the MPSC and the status of recovery for these costs:
In Millions ------------------------------------------------------------------------------------------------------------------- Recoverable, including (b) cost of money through Year Filed Year Incurred Requested Disallowed Allowed 2003 ------------------------------------------------------------------------------------------------------------------- 1999 1997 & 1998 $20 $5 $15 $22 2000 1999 30 5 25 33 2001 2000 25 5 20 24 2002 2001 8 - 8 9 2003 & 2004 (a) 2002 7 Pending Pending Pending 2004 2003 1 Pending Pending Pending ===================================================================================================================
(a) On March 31, 2004, we requested additional 2002 implementation cost recovery of $5 million related to our former participation in the development of the Alliance RTO. This cost has been expensed; therefore, the amount is not included as a regulatory asset. (b) Amounts include the cost of money through the year prior to the year filed. CE-52 Consumers Energy Company In addition to seeking MPSC approval for these costs, we are pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million for implementation costs related to our former participation in the development of the Alliance RTO. Included in this amount is $5 million pending approval by the MPSC as part of 2002 implementation costs application. The FERC has denied our request for reimbursement and we are appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. We cannot predict the outcome of the appeal process or the amount, if any, we will collect for Alliance RTO development costs. The MPSC disallowed certain costs, determining that these amounts did not represent costs incremental to costs already reflected in electric rates. As of September 30, 2004, we incurred and deferred as a regulatory asset $92 million of implementation costs, which includes $25 million associated with the cost of money. We believe the implementation costs and associated cost of money are fully recoverable in accordance with the Customer Choice Act. In June 2004, following an appeal and remand of initial MPSC orders relating to 1999 implementation costs, the MPSC authorized the recovery of all previously approved implementation costs for the years 1997 through 2001 totaling $88 million. This total includes the cost of money through 2003. Additional carrying costs will be added until collection occurs. The implementation costs will be recovered through surcharges over 36-month collection periods and phased in as applicable rate caps expire. In September 2004, the ALJ issued a Proposal for Decision recommending full recovery of the requested 2002 and 2003 implementation costs. We cannot predict the amount, if any, the MPSC will approve as recoverable costs for these years. Security Costs: The Customer Choice Act, as amended, allows for recovery of new and enhanced security costs as a result of federal and state regulatory security requirements incurred before January 1, 2006. In August 2004, the MPSC approved a settlement agreement that authorizes full recovery of $25 million in requested security costs over a five-year period beginning in September 2004. The amount includes reasonable and prudent security enhancements through December 31, 2005. All retail customers, except customers of alternative electric suppliers, will pay these charges. As a result, in August 2004, we recorded total approved security costs incurred to date, including the cost of money. As of September 30, 2004, we have recorded $21 million in security costs as a regulatory asset. The following table outlines our application filed with the MPSC and the status of recovery for these costs:
In Millions --------------------------------------------------------------------------------------- Year Years Regulatory asset as of Filed Covered Requested September 30, 2004 Allowed --------------------------------------------------------------------------------------- 2004 2001-2005 $25 $21 $25 =======================================================================================
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze-cap periods, including the cost of money. The section also allows deferred recovery of expenses incurred during the rate freeze-cap periods that result from changes in taxes, laws or other state or federal governmental actions. In October 2004, we filed an application with the MPSC seeking recovery of $628 million in costs from 2000 through 2005 under section 10d(4). The request includes capital expenditures in excess of depreciation, Clean Air Act costs, and other expenses related to changes in law or governmental action incurred during the rate freeze-cap period. Of the $628 million, $152 million relates to the cost of money. Also included in this application is $74 million of costs that were also incorporated in our Stranded Costs filings. We cannot predict the amount, if any, the MPSC will CE-53 Consumers Energy Company approve as recoverable. The following table outlines our application filed with the MPSC and the status of recovery for these costs:
In Millions -------------------------------------------------------------------------------- Year Years Filed Covered Requested Allowed -------------------------------------------------------------------------------- 2004 2000-2005 $628 Pending ================================================================================
Transmission Rates: Our application of JOATT transmission rates to customers during past periods is under FERC review. The rates included in these tariffs were applied to certain transmission transactions affecting both Detroit Edison's and our transmission systems between 1997 and 2002. We believe our reserve is sufficient to satisfy our refund obligation to any of our former transmission customers under our former JOATT. TRANSMISSION SALE: In May 2002, we sold our electric transmission system to MTH, a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc. We are currently in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized of approximately $2 million to $3 million. Under an agreement with MTH, our transmission rates are fixed by contract at current levels through December 31, 2005, and are subject to FERC ratemaking thereafter. However, we are subject to certain additional MISO surcharges, which we estimate to be $10 million in 2004. ELECTRIC RATE MATTERS PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The standards relate to restoration after outages, safety, and customer services. The MPSC order calls for financial penalties in the form of customer credits if the standards for the duration and frequency of outages are not met. We met or exceeded all approved standards for year-end results for both 2002 and 2003. As of September 2004, we are in compliance with the acceptable level of performance. We are a member of an industry coalition that has appealed the customer credit portion of the performance standards to the Michigan Court of Appeals. We cannot predict the likely effects of the financial penalties, if any, nor can we predict the outcome of the appeal. Likewise, we cannot predict our ability to meet the standards in the future or the cost of future compliance. POWER SUPPLY COSTS: We were required to provide backup service to ROA customers on a best efforts basis. In October 2003, we provided notice to the MPSC that we would terminate the provision of backup service in accordance with the Customer Choice Act, effective January 1, 2004. To reduce the risk of high electric prices during peak demand periods and to achieve our reserve margin target, we employ a strategy of purchasing 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. As we did in 2004, we are currently planning for a reserve margin of approximately 11 percent for summer 2005, or supply resources equal to 111 percent of projected summer peak load. Of the 2005 supply resources target of 111 percent, approximately 101 percent is expected to be met from owned electric generating plants and long-term power purchase contracts, and approximately 10 percent from short-term contracts, options for physical deliveries, and other agreements. As of September 30, 2004, we have purchased capacity and energy contracts partially covering the estimated reserve margin requirements for 2004 through 2007. As a result, we have recognized an asset of $13 million for unexpired capacity and energy CE-54 Consumers Energy Company contracts. As of October 2004, the total premium costs of electric capacity and energy contracts for 2004 is expected to be approximately $12 million. PSCR: As a result of meeting the transmission capability expansion requirements and the market power test, as discussed within this Note, we have met the requirements under the Customer Choice Act to return to the PSCR process. The PSCR process provides for the reconciliation of actual power supply costs with power supply revenues. This process assures recovery of all reasonable and prudent power supply costs actually incurred by us. In September 2003, we submitted a PSCR filing to the MPSC that reinstates the PSCR process for customers whose rates are no longer frozen or capped as of January 1, 2004. The proposed PSCR charge allows us to recover a portion of our increased power supply costs from large commercial and industrial customers and, subject to the overall rate caps, from other customers. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. In October 2004, the ALJ issued a Proposal for Decision, which recommended approval of our 2004 PSCR factor, with minor adjustments. The PSCR factor recommended for approval includes nitrogen oxide emissions allowance costs and requested transmission costs, less a minor adjustment. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $32 million in 2004. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from all other customers. Unless we receive an order from the MPSC, we expect to self-implement this proposed 2005 PSCR charge in January 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings. OTHER ELECTRIC UNCERTAINTIES THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990 and to supply electricity and steam to Dow. We hold, through two wholly owned subsidiaries, the following assets related to the MCV Partnership and the MCV Facility: - CMS Midland owns a 49 percent general partnership interest in the MCV Partnership, and - CMS Holdings holds, through the FMLP, a 35 percent lessor interest in the MCV Facility. In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 7, Implementation of New Accounting Standards. Our consolidated retained earnings include undistributed earnings from the MCV Partnership of $244 million at September 30, 2004 and $238 million at September 30, 2003. Power Supply Purchases from the MCV Partnership: Our annual obligation to purchase capacity from the MCV Partnership is 1,240 MW through the term of the PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's availability, a levelized average capacity charge of 3.77 cents per kWh, and a fixed energy charge. We also pay a variable energy charge based on our average cost of coal consumed for all kWh delivered. Effective January 1999, we reached a settlement agreement with the CE-55 Consumers Energy Company MCV Partnership that capped capacity payments made on the basis of availability that may be billed by the MCV Partnership at a maximum 98.5 percent availability level. Since January 1993, the MPSC has permitted us to recover capacity charges averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges. Since January 1996, the MPSC has also permitted us to recover capacity charges for the remaining 325 MW of contract capacity with an initial average charge of 2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by 2004 and thereafter. However, due to the frozen retail rates required by the Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions of the PPA are subject to certain limitations discussed below. In 1992, we recognized a loss and established a liability for the present value of the estimated future underrecoveries of power supply costs under the PPA based on the MPSC cost recovery orders. We estimate that 51 percent of the actual cash underrecoveries for 2004 will be charged to the PPA liability, with the remaining portion charged to operating expense as a result of our 49 percent ownership in the MCV Partnership. The remaining liability associated with the loss totaled $6 million at September 30, 2004. We will expense all cash underrecoveries directly to income once the PPA liability is depleted. We expect the PPA liability to be depleted in late 2004. If the MCV Facility's generating availability remains at the maximum 98.5 percent level, our cash underrecoveries associated with the PPA could be as follows:
In Millions ----------------------------------------------------------------------------------------- 2004 2005 2006 2007 ----------------------------------------------------------------------------------------- Estimated cash underrecoveries at 98.5% $ 56 $ 56 $ 55 $ 39 Amount to be charged to operating expense 29 56 55 39 Amount to be charged to PPA liability 27 - - - =========================================================================================
Beginning January 1, 2004, the rate freeze for large industrial customers was no longer in effect and we returned to the PSCR process. Under the PSCR process, we will recover from our customers the approved capacity and fixed energy charges based on availability, up to an availability cap of 88.7 percent as established in previous MPSC orders. Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility: As a result of returning to the PSCR process on January 1, 2004, we returned to dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in order to maximize recovery from electric customers of our capacity and fixed energy payments. This fixed load dispatch increases the MCV Facility's output and electricity production costs, such as natural gas. As the spread between the MCV Facility's variable electricity production costs and its energy payment revenue widens, the MCV Partnership's financial performance and our investment in the MCV Partnership is and will be impacted negatively. Under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. CE-56 Consumers Energy Company Until September 2007, the PPA and settlement agreement require us to pay capacity and fixed energy charges based on the MCV Facility's actual availability up to the 98.5 percent cap. After September 2007, we expect to claim relief under the regulatory out provision in the PPA, limiting our capacity and fixed energy payments to the MCV Partnership to the amount collected from our customers. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 2007 may affect negatively the earnings of the MCV Partnership and the value of our investment in the MCV Partnership. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. Resource Conservation Plan: In February 2004, we filed the RCP with the MPSC that is intended to help conserve natural gas and thereby improve our investment in the MCV Partnership. This plan seeks approval to: - dispatch the MCV Facility based on natural gas market prices without increased costs to electric customers, - give Consumers a priority right to buy excess natural gas as a result of the reduced dispatch of the MCV Facility, and - fund $5 million annually for renewable energy sources such as wind power projects. The RCP will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit Consumers' ownership interest in the MCV Partnership. The amount of PPA capacity and fixed energy payments recovered from retail electric customers would remain capped at 88.7 percent. Therefore, customers will not be charged for any increased power supply costs, if they occur. Consumers and the MCV Partnership have reached an agreement that the MCV Partnership will reimburse Consumers for any incremental power costs incurred to replace the reduction in power dispatched from the MCV Facility. In August 2004, several qualifying facilities sought and obtained a stay of the RCP proceeding from the Ingham County Circuit Court after their previous attempt to intervene in the proceeding was denied by the MPSC. In an attempt to resolve this intervention issue as quickly as possible, the MPSC issued an order permitting the qualifying facilities to participate as intervenors. As a result, the Ingham County Circuit Court stay was lifted and hearings were completed in October 2004. The MPSC has decided to dispense with a Proposal for Decision from the presiding ALJ and will issue a decision directly. We cannot predict if or when the MPSC will approve the RCP. The two most significant variables in the analysis of the MCV Partnership's future financial performance are the forward price of natural gas for the next 20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of capacity and fixed energy payments. Historically, natural gas prices have been volatile. Presently, there is no consensus in the marketplace on the price or range of future prices of natural gas. Even with an approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment of our investment in the MCV Partnership. We presently cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our investment in the MCV Partnership. MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict CE-57 Consumers Energy Company the outcome of these proceedings; therefore, the above refund (net of approximately $16 million of deferred expenses) has not been recognized in year-to-date 2004 earnings. NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates for Big Rock and Palisades assume that each plant site will eventually be restored to conform to the adjacent landscape and all contaminated equipment will be disassembled and disposed of in a licensed burial facility. 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 each plant on March 31, 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. Since Big Rock is currently in the process of being decommissioned, the estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. The Palisades cost estimate assumes the plant will be safely stored and subsequently decommissioned. In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding the decommissioning trust funds for both sites. In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. The MPSC order set the annual decommissioning surcharge for Palisades at $6 million through 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability. However, based on current projections, the current level of funds provided by the trusts is not adequate to fully fund the decommissioning of Big Rock or Palisades. This is due in part to the DOE's failure to accept the spent nuclear fuel and lower returns on the trust funds. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation, as discussed below in "Nuclear Matters" within this Note. We will also seek additional relief from the MPSC. In the case of Big Rock, excluding the additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we are currently projecting that the level of funds provided by the trust will fall short of the amount needed to complete the decommissioning by $26 million. At this point in time, we plan to provide the additional amounts needed from our corporate funds and, subsequent to the completion of radiological decommissioning work, seek recovery of such expenditures at the MPSC. We cannot predict how the MPSC will rule on our request. In the case of Palisades, excluding additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we have concluded that the existing surcharge needs to be increased to $25 million annually, beginning January 1, 2006, and continue through 2011, our current license expiration date. In June 2004, we filed an application with the MPSC seeking approval to increase the surcharge for recovery of decommissioning costs related to Palisades beginning in 2006. In September 2004, we announced that we will seek a 20-year license renewal for Palisades. We cannot predict what effect the application and announcement may have on the MPSC request. NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor vessel, steam drum, and radioactive waste processing systems in 2003, dismantlement of plant systems is nearly complete and demolition of the remaining plant structures is set to begin. The restoration project is on schedule to return approximately 530 acres of the site, including the area formerly occupied by the nuclear plant, to a natural setting for unrestricted use in mid-2006. An additional 30 acres, the area where seven transportable dry casks loaded with spent nuclear fuel and an eighth cask loaded with high-level radioactive waste material are stored, will be returned to a natural state by the end of 2012 if the DOE CE-58 Consumers Energy Company begins removing the spent nuclear fuel by 2010. The NRC and the MDEQ continue to find all decommissioning activities at Big Rock are being performed in accordance with applicable regulations including license requirements. Palisades: In August 2004, the NRC completed its mid-cycle plant performance assessment of Palisades. The assessment for Palisades covered the first half of 2004. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. As of September 2004, all inspection findings were classified as having very low safety significance and all performance indicators show performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through March 2006. Our Palisades plant is currently undergoing a regularly scheduled refueling outage. In conjunction with this scheduled outage, we have completed inspection of all 54 nuclear reactor vessel head penetrations. Small cracks were identified in the welds on two of the 45 control rod drive penetration nozzles. No external primary coolant system leakage or damage to the reactor head material was noted. Sections of the two penetrations have been removed and replaced. Post-weld testing, restoration of the support attachments, and reactor head installation on the vessel are in progress and are expected to be complete by mid-November. The total outage extension caused by the weld cracks will be approximately four weeks. The plant is expected to return to service by the end of November. We expect to have sufficient power at all times to meet our load requirements from our other plants or purchase arrangements. These replacement power requirements could increase the cost of power by an estimated $1.6 million (pretax) per week during an extended refueling outage. Of this estimated amount, approximately $0.6 million per week is not recoverable from our customers. The preliminary estimate of the cost of repair to the reactor vessel is $5 million. Our ability to make off-system sales may also be affected by an extension of the refueling outage. However, until all repairs are made, there can be no assurance of the length and effect of the outage on our operations and consolidated earnings. The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of September 30, 2004, we have loaded 22 dry casks with spent nuclear fuel. In September 2004, we announced that we will seek a license renewal for the Palisades plant. The plant's current license from the NRC expires in 2011. NMC, which operates the facility, will apply for a 20-year license renewal for the plant on behalf of Consumers. The Palisades renewal application is scheduled to be filed in the first quarter of 2005. 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. In July 2004, the DOE filed an amended answer and motion to dismiss the complaint. CE-59 Consumers Energy Company In October 2004, we filed a response to the DOE's motion and our motion for summary judgment on liability. The motions are expected to be heard in late 2004 or early 2005. If our litigation against the DOE is successful, we anticipate future recoveries from the DOE. We plan to use recoveries to pay the cost of spent nuclear fuel storage until the DOE takes possession as required by law. We can make no assurance that the litigation against the DOE will be successful. In July 2002, Congress approved and the President signed a bill designating the site at Yucca Mountain, Nevada, for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE will submit, by December 2004, an application to the NRC for a license to begin construction of the repository. The application and review process is estimated to take several years. Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council, the Public Interest Research Group in Michigan, and the Michigan Consumer Federation filed a complaint with the MPSC, which was served on us by the MPSC in April 2003. The complaint asks the MPSC to initiate a generic investigation and contested case to review all facts and issues concerning costs associated with spent nuclear fuel storage and disposal. The complaint seeks a variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service Corporation. The complaint states that amounts collected from customers for spent nuclear fuel storage and disposal should be placed in an independent trust. The complaint also asks the MPSC to take additional actions. In May 2003, Consumers and other named utilities each filed motions to dismiss the complaint. We are unable to predict the outcome of this matter. 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 $27 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 hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. The United States Congress enacted the Price-Anderson Act to provide financial liability protection for those parties who may be liable for a nuclear accident or incident. Part of the Price-Anderson Act's financial protection is a mandatory industry-wide program where 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 $10 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. Big Rock remains insured for nuclear liability by a combination of insurance and a NRC indemnity totaling $544 million, and 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. CE-60 Consumers Energy Company COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional purchase obligations that represent normal business operating contracts. These contracts are used to assure an adequate supply of goods and services necessary for the operation of our business and to minimize exposure to market price fluctuations. We believe that these future costs are prudent and reasonably assured of recovery in future rates. Coal Supply and Transportation: We have entered into coal supply contracts with various suppliers and associated rail transportation contracts for our coal-fired generating stations. Under the terms of these agreements, we are obligated to take physical delivery of the coal and make payment based upon the contract terms. Our coal supply contracts expire through 2006, and total an estimated $154 million. Our coal transportation contracts expire through 2007, and total an estimated $92 million. Long-term coal supply contracts have accounted for approximately 60 to 90 percent of our annual coal requirements over the last 10 years. Although future contract coverage is not finalized at this time, we believe that it will be within the historic 60 to 90 percent range. Power Supply, Capacity, and Transmission: As of September 30, 2004, we had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2004 and 2005 totaling $6 million. We also had 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 2004 through 2030 total an estimated $4.496 billion, undiscounted. This amount may vary depending upon plant availability and fuel costs. If a plant were not available to deliver electricity to us, then we would not be obligated to make the capacity payment until the plant could deliver. GAS CONTINGENCIES GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial 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. We have completed initial investigations at the 23 sites. We will continue to implement remediation plans for sites where we have received MDEQ remediation plan approval. We will also work toward resolving environmental issues at sites as studies are completed. We have estimated our costs for investigation and remedial action at all 23 sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost Model. We expect our remaining costs to be between $37 million and $90 million. The range reflects multiple alternatives with various assumptions for resolving the environmental issues at each site. The estimates are based on discounted 2003 costs using a discount rate of three percent. The discount rate represents a ten-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 insurance proceeds and through the MPSC approved rates charged to our customers. As of September 30, 2004, we have recorded a regulatory liability of $40 million, net of $41 million of expenditures incurred to date, and a regulatory asset of $65 million. 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. In its November 2002 gas distribution rate order, the MPSC authorized us to continue to recover approximately $1 million of manufactured gas plant facilities environmental clean-up costs annually. CE-61 Consumers Energy Company This amount will continue to be offset by $2 million to reflect amounts recovered from all other sources. We defer and amortize, over a period of 10 years, manufactured gas plant facilities environmental clean-up costs above the amount currently included in rates. Additional amortization of the expense in our rates cannot begin until after a prudency review in a gas rate case. GAS RATE MATTERS GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers for our actual cost of purchased natural gas. The GCR process is designed to allow us to recover all of our prudently incurred gas costs. The MPSC reviews these costs for prudency in an annual reconciliation proceeding. The following table summarizes our GCR reconciliation filings with the MPSC. Additional details related to these proceedings follow the table. Gas Cost Recovery Reconciliation
Net Over GCR Year Date Filed Order Date Recovery Status ---------------------------------------------------------------------------------------------------------------- 2001-2002 June 2002 May 2004 $3 million $2 million has been refunded; $1 million is included in our 2003-2004 GCR reconciliation filing 2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest accrued through March 2003, and an $11 million disallowance settlement agreement. 2003-2004 June 2004 Pending $28 million Filing includes the $1 million and $5 million GCR net overrecovery above ================================================================================================================
Net overrecovery amounts included in the table above include refunds received by us from our suppliers and required by the MPSC to be refunded to our customers. GCR year 2001-2002: In June 2002, we filed a reconciliation of GCR costs and revenues for the 12-months ended March 2002. In May 2004, the MPSC issued an order directing us to refund a net overrecovery of $3 million, plus interest. Of this, $2 million has been refunded and the remaining $1 million is included in our 2003-2004 GCR year reconciliation filing. GCR year 2002-2003: In June 2003, we filed a reconciliation of GCR costs and revenues for the 12-months ended March 2003. We proposed to recover from our customers approximately $6 million of underrecovered gas costs, including interest through March 2003, using a roll-in methodology. The roll-in methodology incorporates a GCR over/underrecovery in the next GCR plan year. The approach was approved by the MPSC in a November 2002 order. In January 2004, intervenors filed their positions in our 2002-2003 GCR reconciliation case. Their positions were that not all of our gas purchasing decisions were prudent from April 2002 through March 2003 and they proposed disallowances. In 2003, we reserved $11 million for a 2002-2003 GCR disallowance. Interest on this amount from April 2003 through February 2004, at our authorized rate of return, increased this amount by $1 million. The interest was recorded as an expense in 2003. In March 2004, the parties in the case reached a settlement agreement that resulted in a GCR disallowance of $11 million for the GCR period. The settlement agreement was approved by the MPSC in March 2004. The prior year $6 million underrecovery and $11 million disallowance are included in our 2003-2004 GCR year filing using the roll-in methodology. The roll-in methodology incorporates the CE-62 Consumers Energy Company GCR underrecovery in the next GCR plan year. The approach was approved by the MPSC in a November 2002 order. GCR year 2003-2004: In June 2004, we filed a reconciliation of GCR costs and revenues for the 12-months ended March 2004. We proposed to refund to our customers $28 million of overrecovered gas cost, plus interest. We proposed that the refund be included in the 2004-2005 GCR plan year. The overrecovery includes the $1 million refund for the 2001-2002 GCR reconciliation case, the $11 million refund settlement for the 2002-2003 GCR reconciliation case, as well as refunds received by us from our suppliers and required by the MPSC to be refunded to our customers. GCR plan for year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding. Recent increases in gas prices could cause us to incur costs in excess of what can be recovered pursuant to the current ceiling price. We are permitted to apply to the MPSC to modify the ceiling price, and will do so if necessary. In addition, if actual, prudently incurred costs exceed the ceiling price, the difference can be recovered through the reconciliation proceeding. Our GCR factor for the billing month of November 2004 is $6.55 per mcf. 2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. On December 18, 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes. On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon receipt of a letter signed by the Chairman of Consumers and CMS Energy which agrees to: - achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached, - make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted, - refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate, - prepare and file annual reports that address certain issues identified in the order, and - file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect). On October 15, 2004, Consumers' and CMS Energy's Chairman filed a letter with the MPSC making the commitments required by the rate order. On October 19, 2004, we filed rehearing petitions with the MPSC, which seek clarification of the method of computing our rate of return on common equity. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003 the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case. CE-63 Consumers Energy Company On October 14, 2004, the MPSC issued its Opinion and Order in our gas depreciation case. The order restores depreciation rates to the levels that were in effect prior to the issuance of the December 18, 2003 interim gas rate order. The final order further requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to have book depreciation rates restored to the level set forth in the MPSC's prior interim gas rate relief order. GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an order rejecting our filing to assess certain rates for non-physical gas title tracking services we provide. In December 2003, the FERC ruled that no refunds were at issue and we reversed a $4 million reserve related to this matter. In January 2004, three companies filed with the FERC for clarification or rehearing of the FERC's December 2003 order. In April 2004, the FERC issued its Order Granting Clarification. In that Order, the FERC indicated that its December 2003 order was in error. It directed us to file within 30 days a fair and equitable title-tracking fee and to make refunds, with interest, to customers based on the difference between the accepted fee and the fee paid. In response to the FERC's April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued an Order Granting Rehearing for Further Consideration in June 2004. We expect the FERC to issue an order on the merits of this proceeding. We believe that with respect to the FERC jurisdictional transportation, we have not charged any customers title transfer fees, so no refunds are due. At this time, we cannot predict the outcome of this proceeding. OTHER UNCERTAINTIES In addition to the matters disclosed within this Note, we 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 results of operations. CE-64 Consumers Energy Company 3: FINANCINGS AND CAPITALIZATION Long-term debt is summarized as follows:
In Millions ------------------------------------------------------------------------------------------------------------ September 30, 2004 December 31, 2003 ------------------------------------------------------------------------------------------------------------ First mortgage bonds $ 2,283 $ 1,483 Senior notes 813 1,254 Bank debt and other 356 469 Securitization bonds 406 426 FMLP debt 296 - ---------------------------------------------- Principal amounts outstanding 4,154 3,632 Current amounts (148) (28) Net unamortized discount (20) (21) ------------------------------------------------------------------------------------------------------------ Total Long-term debt $ 3,986 $ 3,583 ============================================================================================================
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB Interpretation No. 46. At September 30, 2004, long-term debt of the FMLP consists of:
In Millions ------------------------------------------------------------------------------------------------------------ Maturity 2004 ------------------------------------------------------------------------------------------------------------ 11.75% subordinated secured notes 2005 $ 70 13.25% subordinated secured notes 2006 75 6.875% tax-exempt subordinated secured notes 2009 137 6.75% tax-exempt subordinated secured notes 2009 14 ------------------------------------------------------------------------------------------------------------ Total amount outstanding $ 296 ============================================================================================================
The FMLP debt is essentially project debt secured by certain assets of the MCV Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy and Consumers. The following is a summary of significant long-term debt issuances and retirements during 2004:
Principal Issue/Retirement (In millions) Interest Rate Date Maturity Date ------------------------------------------------------------------------------------------------------------ DEBT ISSUANCES FMB $ 150 4.40% August 2004 August 2009 FMB 300 5.00% August 2004 February 2012 FMB 350 5.50% August 2004 August 2016 ------------------------------------------------------------------------------------------------------------ Total debt issuances $ 800 ============================================================================================================ DEBT RETIREMENTS FMLP debt $ 115 11.75% July 2004 July 2004 Long-term bank debt 140 Variable August 2004 March 2009 Senior notes 141 6.50% September 2004 June 2018 Senior notes 300 6.00% September 2004 March 2005 ------------------------------------------------------------------------------------------------------------ Total debt retirements $ 696 ============================================================================================================
Issuance costs associated with the 2004 FMB issuances total $5 million and are being amortized ratably over the lives of the related debt. Call premiums associated with 2004 debt retirements totaled CE-65 Consumers Energy Company $13 million and are being amortized ratably over the lives of the newly issued debt. In September 2004, we issued $30 million of 3.375 percent Limited Obligation Revenue Bonds. Consequently, we redeemed $30 million of 5.8 percent Limited Obligation Revenue Bonds in October 2004. DEBT MATURITIES: At September 30, 2004, the aggregate annual maturities for long-term debt for the three months ending December 31, 2004 and the next four years are:
In Millions -------------------------------------------------------------------------------- Payments Due -------------------------------------------------------------------------------- December 31 2004 2005 2006 2007 2008 -------------------------------------------------------------------------------- Long-term debt $ 38 $ 118 $ 478 $ 59 $ 504 ================================================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: We have FERC authorization to issue or guarantee up to $1.1 billion of short-term securities and up to $1.1 billion of short-term first mortgage bonds as collateral for such short-term securities. We have FERC authorization to issue up to $1 billion of long-term securities for refinancing or refunding purposes, $1.5 billion of long-term securities for general corporate purposes, and $2.5 billion of long-term first mortgage bonds to be issued solely as collateral for other long-term securities. SHORT-TERM FINANCINGS: At September 30, 2004, we had a $500 million secured revolving credit facility with banks, which expires July 31, 2007. At September 30, 2004, $25 million of letters of credit were issued and outstanding under this facility and $475 million was available for general corporate purposes, working capital, and letters of credit. The MCV Partnership had a $50 million working capital facility available. FIRST MORTGAGE BONDS: We secure our first mortgage bonds by a mortgage and lien on substantially all of our property. Our ability to issue and sell securities is restricted by certain provisions in the first mortgage bond indenture, our articles of incorporation, and the need for regulatory approvals under federal law. CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly of leased service vehicles and office furniture. As of September 30, 2004, capital lease obligations totaled $62 million. In order to obtain permanent financing for the MCV Facility, the MCV Partnership entered into a sale and lease back agreement with a lessor group, which includes the FMLP, for substantially all of the MCV Partnership's fixed assets. In accordance with SFAS No. 98, the MCV Partnership accounted for the transaction as a financing arrangement. As of September 30, 2004, finance lease obligations totaled $285 million, which represents the third-party portion of the MCV Partnership's finance lease obligation. SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we currently 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. We sold $50 million of receivables at September 30, 2004 and we sold $254 million at September 30, 2003. These sold amounts are excluded from accounts receivable on our Consolidated Balance Sheets. 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 the purchaser has no right to any receivables not sold. No gain or loss has been recorded on the receivables sold and we retain no interest in the receivables sold. CE-66 Consumer Energy Company Certain cash flows under our accounts receivable sales program are shown in the following table:
In Millions -------------------------------------------------------------------------------- Nine Months Ended September 30 2004 2003 -------------------------------------------------------------------------------- Net cash flow as a result of A/R financing $ (247) $ (71) Collections from customers $ 3,542 $ 3,379 ================================================================================
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at September 30, 2004, we had $348 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim order, which included a $190 million annual dividend cap. For the nine months ended September 30, 2004, we paid $187 million in common stock dividends to CMS Energy. FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENT FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: This Interpretation became effective January 2003. It describes the disclosure to be made by a guarantor about its obligations under certain guarantees that it has issued. At the beginning of a guarantee, it requires a guarantor to recognize a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provision of this Interpretation does not apply to some guarantee contracts, such as warranties, derivatives, or guarantees between either parent and subsidiaries or corporations under common control, although disclosure of these guarantees is required. For contracts that are within the recognition and measurement provision of this Interpretation, the provisions were to be applied to guarantees issued or modified after December 31, 2002. The following tables describe our guarantees at September 30, 2004:
In Millions --------------------------------------------------------------------------------------------------------- Issue Expiration Maximum Carrying Recourse Guarantee Description Date Date Obligation Amount Provision (a) --------------------------------------------------------------------------------------------------------- Standby letters of credit Various Various $ 25 $ - $ - Surety bonds Various Various 5 - - Nuclear insurance retrospective premiums Various Various 134 - - =========================================================================================================
(a) Recourse provision indicates the approximate recovery from third parties including assets held as collateral.
Events That Would Require Guarantee Description How Guarantee Arose Performance ------------------------------------------------------------------------------------------------------------- Standby letters of credit Normal operations of coal power Noncompliance with plants environmental regulations Natural gas transportation Nonperformance Self-insurance requirement Nonperformance Nuclear plant closure Nonperformance Surety bonds Normal operating activity, permits Nonperformance and license Nuclear insurance retrospective Normal operations of nuclear plants Call by NEIL and Price-Anderson premiums Act for nuclear incident =============================================================================================================
CE-67 Consumer Energy Company 4: 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 carrying amount of all long-term financial instruments, except as shown below, approximates fair value. Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $140 million as of September 30, 2004. These securities represent funds restricted primarily for future lease payments and are classified as Other Assets on the Consolidated Balance Sheets. These investments have original maturity dates of approximately one year or less and, because of their short maturities, their carrying amounts approximate their fair values. For additional details, see Note 1, Corporate Structure and Accounting Policies.
In Millions ------------------------------------------------------------------------------------------------------------------ September 30 2004 2003 ------------------------------------------------------------------------------------------------------------------ Fair Unrealized Fair Unrealized Cost Value Gain (Loss) Cost Value Gain (Loss) ------------------------------------------------------------------------------------------------------------------ Long-term debt (a) $ 4,134 $ 4,267 $ (133) $ 3,559 $ 3,677 $ (118) Long-term debt - related parties (b) 506 515 (9) - - - Trust Preferred Securities (b) - - - 490 497 (7) Available-for-sale securities: Common stock of CMS Energy (c) 10 22 12 10 17 7 SERP 17 21 4 17 20 3 Nuclear decommissioning investments (d) 431 551 120 450 553 103 ==================================================================================================================
(a) Includes current maturities of $148 million at September 30, 2004 and $28 million at September 30, 2003. Settlement of long-term debt is generally not expected until maturity. (b) We determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities have been deconsolidated as of December 31, 2003 and are reflected in Long-term debt - related parties on the Consolidated Balance Sheets. For additional details, see Note 7, Implementation of New Accounting Standards. (c) As of September 30, 2004, we held 2.4 million shares of CMS Energy Common Stock. (d) Our unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities. DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, and equity security prices. We manage these risks 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. We may use various contracts to manage these risks including swaps, options, futures, and forward contracts. We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. We enter into all risk management contracts for purposes other than trading. These contracts contain credit risk if the counterparties, including financial institutions and energy marketers, CE-68 Consumer Energy Company fail to perform under the agreements. We minimize such risk by performing financial credit reviews using, among other things, publicly available credit ratings of such counterparties. Contracts used to manage interest rate and commodity price risk may be considered derivative instruments that are subject to derivative and hedge accounting pursuant to SFAS No. 133. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as an asset or a liability, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in the fair value of a derivative (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income depending on whether the derivative qualifies for special hedge accounting treatment. For derivative instruments to qualify for hedge accounting under SFAS No. 133, the hedging relationship must be formally documented at inception and be highly effective in achieving offsetting cash flows or offsetting changes in fair value attributable to the risk being hedged. If hedging a forecasted transaction, the forecasted transaction must be probable. If a derivative instrument, used as a cash flow hedge, is terminated early because it is probable that a forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If a derivative instrument, used as a cash flow hedge, is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and recorded when the forecasted transaction affects earnings. We use a combination of quoted market prices and mathematical valuation models to determine fair value of those contracts requiring derivative accounting. The ineffective portion, if any, of all hedges is recognized in earnings. The majority of our contracts are not subject to derivative accounting because they qualify for the normal purchases and sales exception of SFAS No. 133, or are not derivatives because there is not an active market for the commodity. Our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market, as defined by SFAS No. 133, for the coal that we purchase. If active markets develop in the future, we may be required to account for these contracts as derivatives. The mark-to-market impact on earnings related to these contracts could be material to the financial statements. The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which will include day-ahead and real-time energy market information for the MISO's participants. We are presently evaluating what impacts, if any, this market development will have on the determination of whether an active energy market exists in the state of Michigan. CE-69 Consumers Energy Company Derivative accounting is required for certain contracts used to limit our exposure to commodity price risk and interest rate risk. The following table reflects the fair value of all contracts requiring derivative accounting:
In Millions --------------------------------------------------------------------------------------------------------------------- September 30 2004 2003 --------------------------------------------------------------------------------------------------------------------- Fair Unrealized Fair Unrealized Derivative Instruments Cost Value Gain Cost Value Gain (Loss) --------------------------------------------------------------------------------------------------------------------- Gas contracts $ 2 $ 5 $ 3 $ 3 $ - $ (3) Derivative contracts associated with Consumers' investment in the MCV Partnership: Prior to consolidation - - - - 10 10 After consolidation: Gas fuel contracts - 80 80 - - - Gas fuel futures and swaps - 92 92 - - - ======================================================================================================================
The fair value of our derivative contracts is included in Derivative Instruments, Other Assets, or Other Liabilities on our Consolidated Balance Sheets. The fair value of derivative contracts associated with our investment in the MCV Partnership for 2003 is included in Investments - Midland Cogeneration Venture Limited Partnership on our Consolidated Balance Sheets. ELECTRIC CONTRACTS: Our electric utility business may use purchased electric call option contracts to meet, in part, our regulatory obligation to serve. This obligation requires us to provide a physical supply of electricity to customers, to manage electric costs, and to ensure a reliable source of capacity during peak demand periods. As of September 30, 2004 and September 30, 2003, we did not have any purchased electric call options outstanding that were accounted for as derivatives. GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas supply contracts, fixed price weather-based gas supply call options, fixed price gas supply call and put options, and other types of contracts, to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. Unrealized gains and losses associated with these options are reported directly in earnings as part of other income, and then directly offset in earnings and recorded on the balance sheet as a regulatory asset or liability as part of the GCR process. At September 30, 2004, we held fixed-priced weather-based gas supply call options and fixed-price gas supply put options. INTEREST RATE RISK CONTRACTS: We frequently use interest rate swaps to hedge the risk associated with forecasted interest payments on variable-rate debt and to reduce the impact of interest rate fluctuations. These interest rate swaps are generally designated as cash flow hedges. As such, we record changes in the fair value of these contracts in accumulated other comprehensive income unless the swaps are sold. As of September 30, 2004 and September 30, 2003, we did not have any interest rate swaps outstanding. DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV PARTNERSHIP: Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that its long-term natural gas contracts, which do not contain volume optionality, qualify under SFAS No. 133 for the normal purchases and normal sales exception. Therefore, these contracts are currently not recognized at fair value on the balance sheet. Should significant changes in the level of the MCV Facility operational dispatch or purchases of long-term gas occur, the MCV Partnership would be required to re-evaluate its CE-70 Consumers Energy Company accounting treatment for these long-term gas contracts. This re-evaluation may result in recording mark-to-market activity on some contracts, which could add to earnings volatility. At September 30, 2004, the MCV Partnership had six long-term gas contracts that contained both an option and forward component. Because of the option component, these contracts do not qualify for the normal purchases and sales exception and are accounted for as derivatives, with changes in fair value recorded in earnings each quarter. The MCV Partnership expects future earnings volatility on these contracts, since gains or losses will be recorded each quarter. At September 30, 2004, the MCV Partnership also held three long-term gas contracts that were previously accounted for as derivatives but qualified for the normal purchases and sales exception starting in the fourth quarter of 2002. At that time, the fair value of these contracts was frozen and is being amortized over the remaining life of the contracts. For the nine months ended September 30, 2004, we recorded a $5 million net gain associated with the MCV Partnership's long-term gas fuel contracts in Fuel for electric generation on our Consolidated Statements of Income. The fair value of these contracts will reverse over the remaining life of the contracts ranging from 2004 to 2007. Gas Fuel Futures and Swaps: To manage market risks associated with the volatility of natural gas prices, the MCV Partnership maintains a gas hedging program. The MCV Partnership enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements. At September 30, 2004, the MCV Partnership held gas fuel futures and swaps. These financial instruments are accounted for as derivatives under SFAS No. 133. The contracts that are used to secure anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133. The MCV Partnership also engages in cost mitigation activities to offset the fixed charges the MCV Partnership incurs in operating the MCV Facility. These cost mitigation activities include the use of futures and options contracts to purchase and/or sell natural gas to maximize the use of the transportation and storage contracts when it is determined that they will not be needed for the MCV Facility operation. Although these cost mitigation activities do serve to offset the fixed monthly charges, these cost mitigation activities are not considered a normal course of business for the MCV Partnership and do not qualify as hedges under SFAS No. 133. Therefore, the mark-to-market gains and losses from these cost mitigation activities are recorded in earnings each quarter. As of September 30, 2004, we have recorded a cumulative net gain of $30 million, net of tax, in accumulated other comprehensive income relating to our proportionate share of the contracts held by the MCV Partnership that qualify as cash flow hedges. This balance represents natural gas futures, options, and swaps with maturities ranging from October 2004 to December 2009, of which $17 million of this gain is expected to be reclassified as an increase to earnings during the next 12 months. In addition, for the nine months ended September 30, 2004, we recorded a net gain of $21 million in earnings from hedging activities related to natural gas requirements for the MCV Facility operations and a net gain of $1 million in earnings from the MCV Partnership's cost mitigation activities. CE-71 Consumers Energy Company 5: RETIREMENT BENEFITS We provide retirement benefits to our employees under a number of different plans, including: - non-contributory, defined benefit Pension Plan, - a cash balance pension plan for certain employees hired after June 30, 2003, - benefits to certain management employees under SERP, - health care and life insurance benefits under OPEB, - benefits to a select group of management under EISP, and - a defined contribution 401(k) plan. Pension Plan: The Pension Plan includes funds for our employees and our non-utility affiliates, including former Panhandle employees. The Pension Plan's assets are not distinguishable by company. As of September 30, 2004, we have recorded a prepaid pension asset of $369 million, $20 million of which is in Other current assets on our Consolidated Balance Sheets. OPEB: We adopted SFAS No. 106, effective as of 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." In 1994, the MPSC authorized recovery of the electric utility portion of these costs over 18 years and in 1996, the MPSC authorized recovery of the gas utility portion of these costs over 16 years. We have made contributions of $47 million to our 401(h) and VEBA trust funds in 2004. We plan to make additional contributions of $15 million in 2004. Costs: The following table recaps the costs incurred in our retirement benefits plans:
In Millions ------------------------------------------------------------------------------- Pension Three Months Ended Nine Months Ended ------------------------------------------------------------------------------- September 30 2004 2003 2004 2003 ------------------------------------------------------------------------------- Service cost $ 10 $ 10 $ 29 $ 29 Interest expense 17 18 53 55 Expected return on plan assets (26) (20) (80) (61) Amortization of: Net loss 3 2 10 7 Prior service cost 1 1 4 5 ------------------------------------- Net periodic pension cost $ 5 $ 11 $ 16 $ 35 ===============================================================================
CE-72 Consumers Energy Company
In Millions ------------------------------------------------------------------------------- OPEB Three Months Ended Nine Months Ended ------------------------------------------------------------------------------- September 30 2004 2003 2004 2003 ------------------------------------------------------------------------------- Service cost $ 4 $ 5 $ 13 $ 14 Interest expense 14 15 41 46 Expected return on plan assets (11) (10) (34) (30) Amortization of: Net loss 3 5 9 14 Prior service cost (2) (2) (6) (5) ---------------------------------- Net periodic postretirement benefit cost $ 8 $ 13 $ 23 $ 39 ===============================================================================
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004 in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $148 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $17 million for the nine months ended September 30, 2004, and an expected total reduction of $23 million for 2004. The reduction of $23 million includes $7 million in capitalized OPEB costs. For additional details, see Note 7, Implementation of New Accounting Standards. 6: ASSET RETIREMENT OBLIGATIONS SFAS NO. 143: This standard became effective January 2003. It 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 do so. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. Before adopting this standard, we classified the removal cost of assets included in the scope of SFAS No. 143 as part of the reserve for accumulated depreciation. For these assets, the removal cost of $448 million that was classified as part of the reserve at December 31, 2002, was reclassified in January 2003, in part, as a: - $364 million ARO liability, - $134 million regulatory liability, - $42 million regulatory asset, and - $7 million net increase to property, plant, and equipment as prescribed by SFAS No. 143. We are reflecting a regulatory asset and liability as required by SFAS No. 71 for regulated entities 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 CE-73 Consumers Energy Company 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 five percent market risk premium were assumed, our ARO liability would increase by $22 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, 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. 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 are based on decommissioning studies that largely utilize third-party cost estimates. The following tables describe our assets that have legal obligations to be removed at the end of their useful life.
September 30, 2004 In Millions --------------------------------------------------------------------------------------------------------------------- In Service Trust ARO Description Date Long Lived Assets Fund --------------------------------------------------------------------------------------------------------------------- Palisades - decommission plant site 1972 Palisades nuclear plant $500 Big Rock - decommission plant site 1962 Big Rock nuclear plant 51 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 - =====================================================================================================================
September 30, 2004 In Millions ------------------------------------------------------------------------------------------------------------------------- ARO Liability ARO ------------- Cash flow Liability ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 9/30/04 ------------------------------------------------------------------------------------------------------------------------- Palisades - decommission $249 $268 $ - $ - $16 $60 $344 Big Rock - decommission 61 35 - (32) 10 22 35 JHCampbell intake line - - - - - - - Coal ash disposal areas 51 52 - (2) 4 - 54 Wells at gas storage fields 2 2 - - - - 2 Indoor gas services relocations 1 1 - - - - 1 ----------------------------------------------------------------------------------- Total $364 $358 $ - $(34) $30 $82 $436 =========================================================================================================================
The Palisades and Big Rock cash flow revisions resulted from new decommissioning reports filed with the MPSC in March 2004. The Palisades ARO also reflects a cash flow revision for the probability of operating license renewal; the renewal would extend the plant's operating license by twenty years. For additional details, see Note 2, Uncertainties, "Other Electric Uncertainties - Nuclear Plant Decommissioning." Reclassification of certain types of Cost of Removal: Beginning in December 2003, the SEC requires the quantification and reclassification of the estimated cost of removal obligations arising from other than legal obligations. These cost of removal obligations have been accrued through depreciation CE-74 Consumers Energy Company charges. We estimate that we had $1.026 billion at September 30, 2004 and $962 million at September 30, 2003 of previously accrued asset removal costs related to our regulated operations arising from other than legal obligations. These obligations, which were previously classified as a component of accumulated depreciation, are now classified as regulatory liabilities in the accompanying Consolidated Balance Sheets. 7: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The FASB issued this Interpretation in January 2003. The objective of the Interpretation is to assist in determining when one party controls another entity in circumstances where a controlling financial interest cannot be properly identified based on voting interests. Entities with this characteristic are considered variable interest entities. The Interpretation requires the party with the controlling financial interest, known as the primary beneficiary, in a variable interest entity to consolidate the entity. In December 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that have not previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No. 46 provided an implementation deferral until the first quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation No. 46 for all entities. We determined that we are the primary beneficiary of both the MCV Partnership and the FMLP. We have a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the MCV Facility, which results in Consumers holding a 35 percent lessor interest in the MCV Facility. Collectively, these interests make us the primary beneficiary of these entities. As such, we consolidated their assets, liabilities, and activities into our financial statements for the first time as of and for the quarter ended March 31, 2004. These partnerships have third-party obligations totaling $581 million at September 30, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.440 billion at September 30, 2004. The creditors of these partnerships do not have recourse to the general credit of CMS Energy. We also determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities have been deconsolidated as of December 31, 2003. Company Obligated Trust Preferred Securities totaling $490 million, that were previously included in mezzanine equity, have been eliminated due to deconsolidation. As a result of the deconsolidation, we reflected $506 million of long-term debt - related parties and reflected an investment in related parties of $16 million. We are not required to restate prior periods for the impact of this accounting change. FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003, we elected a one-time deferral of the accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1. CE-75 Consumers Energy Company The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position, No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position, No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations and postretirement benefit costs should reflect the effects of the Act. We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $148 million. The remeasurement resulted in a reduction of OPEB cost of $6 million for the three months ended September 30, 2004, $17 million for the nine months ended September 30, 2004, and an expected total reduction of $23 million for 2004. Consumers capitalizes a portion of OPEB cost in accordance with regulatory accounting. As such, the remeasurement resulted in a net reduction of OPEB expense of $4 million for the three months ended September 30, 2004, $12 million for the nine months ended September 30, 2004, and an expected total net expense reduction of $16 million for 2004. CE-76 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK CMS ENERGY Quantitative and Qualitative Disclosures about Market Risk is contained in PART I: CMS Energy Corporation's Management's Discussion and Analysis, which is incorporated by reference herein. CONSUMERS Quantitative and Qualitative Disclosures about Market Risk is contained in PART I: Consumers Energy Company's Management's Discussion and Analysis, which is incorporated by reference herein. ITEM 4. CONTROLS AND PROCEDURES CMS ENERGY Disclosure Controls and Procedures: CMS Energy's management, with the participation of its CEO and CFO, has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, CMS Energy's CEO and CFO have concluded that, as of the end of such period, its disclosure controls and procedures are effective. Internal Control Over Financial Reporting: There have not been any changes in CMS Energy's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting. CONSUMERS Disclosure Controls and Procedures: Consumers' management, with the participation of its CEO and CFO, has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, Consumers' CEO and CFO have concluded that, as of the end of such period, its disclosure controls and procedures are effective. Internal Control Over Financial Reporting: There have not been any changes in Consumers' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The discussion below is limited to an update of developments that have occurred in various judicial and administrative proceedings, many of which are more fully described in CMS Energy's and Consumers' Forms 10-K/A for the year ended December 31, 2003. Reference is also made to the Condensed Notes to the Consolidated Financial Statements, in particular, Note 3, Uncertainties for CMS Energy and Note 2, Uncertainties for Consumers, included herein for additional information regarding various pending administrative and judicial proceedings involving rate, operating, regulatory and environmental matters. CO-1 CMS ENERGY SEC REQUEST On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy voluntarily produce all documents and data relating to the SEC's inquiry into payments made to the government and officials of the government of Equatorial Guinea. CMS Energy will fully cooperate with the SEC in its inquiry. From 1991 through January 3, 2002, subsidiaries of CMS Energy held interests in, and beginning in 1995 operated, hydrocarbon production and processing facilities and a methanol plant in Equatorial Guinea. On January 3, 2002, CMS Energy sold all its Equatorial Guinea holdings. The SEC's inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the U.S. banking transactions of various foreign governments, including that of Equatorial Guinea. The investigation and hearing also reviewed the operations of certain U.S. oil companies in Equatorial Guinea. There were no findings of violations of the U.S. Foreign Corrupt Practices Act by the U.S. oil companies in the report of the Minority Staff of the Subcommittee, the only report issued to date as a result of the hearing. The Subcommittee did find that oil companies operating in Equatorial Guinea may have contributed to corrupt practices in that country. CMS Energy provided the SEC with a list of documents that may be responsive to its request but the SEC has yet to indicate which documents it wishes to review. SEC INVESTIGATION 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 nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. In March 2004, the SEC also filed an action against three former employees related to round-trip trading by 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. DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS In May 2002, the Board of Directors of CMS Energy received a demand, on behalf of a shareholder of CMS Energy Common Stock, that it commence civil actions (i) to remedy alleged breaches of fiduciary duties by certain CMS Energy officers and directors in connection with round-trip trading by CMS MST, and (ii) to recover damages sustained by CMS Energy as a result of alleged insider trades alleged to have been made by certain current and former officers of CMS Energy and its subsidiaries. In December 2002, two new directors were appointed to the Board. The Board formed a special litigation committee in January 2003 to determine whether it is in CMS Energy's best interest to bring the action demanded by the shareholder. The disinterested members of the Board appointed the two new directors to serve on the special litigation committee. In December 2003, during the continuing review by the special litigation committee, CMS Energy was served with a derivative complaint filed on behalf of the shareholder in the Circuit Court of Jackson County, Michigan in furtherance of his demands. The date for CMS Energy and other defendants to answer or otherwise respond to the complaint has been extended to December 1, 2004, subject to such further extensions as may be mutually agreed upon by the parties and authorized by the Court. CMS Energy cannot predict the outcome of this matter. CO-2 INTEGRUM LAWSUIT Integrum filed a complaint in Wayne County, Michigan Circuit Court in July 2003 against CMS Energy, Enterprises and APT. Integrum alleges several causes of action against APT, CMS Energy, and Enterprises in connection with an offer by Integrum to purchase the CMS Pipeline Assets. In addition to seeking unspecified money damages, Integrum is seeking an order enjoining CMS Energy and Enterprises from selling, and APT from purchasing, the CMS Pipeline Assets and an order of specific performance mandating that CMS Energy, Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT and Integrum. A certain officer and director of Integrum is a former officer and director of CMS Energy, Consumers, and their subsidiaries. The individual was not employed by CMS Energy, Consumers, or their subsidiaries when Integrum made the offer to purchase the CMS Pipeline Assets. CMS Energy and Enterprises filed a motion to change venue from Wayne County to Jackson County, which was granted. The case was then dismissed with prejudice based upon plaintiff's failure to file a transfer fee within the requisite time. Plaintiff has stated it intends to file a motion to have the case reinstated. CMS Energy and Enterprises believe that Integrum's claims are without merit. CMS Energy and Enterprises intend to defend vigorously against this action but they cannot predict the outcome of this litigation. GAS INDEX PRICE REPORTING LITIGATION In August 2003, Cornerstone Propane Partners, L.P. (Cornerstone) filed a putative class action complaint in the United States District Court for the Southern District of New York against CMS Energy and dozens of other energy companies. The court ordered the Cornerstone complaint to be consolidated with similar complaints filed by Dominick Viola and Roberto Calle Gracey. The plaintiffs filed a consolidated complaint on January 20, 2004. The consolidated complaint alleges that false natural gas price reporting by the defendants manipulated the prices of NYMEX natural gas futures and options. The complaint contains two counts under the Commodity Exchange Act, one for manipulation and one for aiding and abetting violations. CMS Energy is no longer a defendant, however, CMS MST and CMS Field Services are named as defendants. (CMS Energy sold CMS Field Services to Cantera Natural Gas, Inc. but is required to indemnify Cantera Natural Gas, Inc. with respect to this action.) In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a putative class action lawsuit in the United States District Court for the Eastern District of California against a number of energy companies engaged in the sale of natural gas in the United States. CMS Energy is named as a defendant. The complaint alleges defendants entered into a price-fixing conspiracy by engaging in activities to manipulate the price of natural gas in California. The complaint contains counts alleging violations of the Sherman Act, Cartwright Act (a California statute), and the California Business and Profession Code relating to unlawful, unfair and deceptive business practices. There is currently pending in the Nevada federal district court a multi district court litigation (MDL) matter involving 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 Sherman Act claim and some of the defendants in the MDL matter are also defendants in the Texas-Ohio case. Those defendants successfully argued to have the Texas-Ohio case transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case agreed to extend the time for all defendants to answer or otherwise respond until May 28, 2004 and on that date a number of defendants filed motions to dismiss. In order to negotiate possible dismissal and/or substitution of defendants, CMS Energy and two other parent holding company defendants were given further extensions to answer or otherwise respond to the complaint until November 16, 2004. Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint containing allegations similar to those made in the Texas-Ohio case, albeit limited to California state law claims, was filed in California state court in February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed a notice to remove this action to California federal district court, which was granted, and CO-3 had it transferred to the MDL proceeding in Nevada. However, the plaintiff is seeking to have the case remanded back to California and until the issue is resolved, no further action will be taken. Another putative class action lawsuit, Fairhaven Power Company v. Encana Power Corporation, containing allegations similar to those made in the Texas-Ohio case, was filed in California federal court in September 2004. CMS Energy, Enterprises, and CMS MST are named as defendants. Three new, virtually identical actions were filed in San Diego Superior Court in July 2004, one by the County of Santa Clara, one by the County of San Diego and one by the City of and County of San Francisco and the San Francisco City Attorney (collectively the Municipal Lawsuits). Defendants, consisting of a number of energy companies including CMS Energy, CMS MST, Cantera Natural Gas, and Cantera Gas Company, are alleged to have engaged in false reporting of natural gas price and volume information and sham sales to artificially inflate natural gas retail prices in California. All three complaints allege claims for unjust enrichment and violations of the Cartwright Act, and the San Francisco action also alleges a claim for violation of the California Business and Profession Code relating to unlawful, unfair and deceptive business practices. The Municipal Lawsuits were removed to federal district court, and conditional transfer orders were issued transferring the cases to the Nevada MDL proceeding. Plaintiffs in each of the Municipal Lawsuits intend to seek to have the cases remanded back to San Diego Superior Court, and they have agreed to extend the time to answer or otherwise respond to the complaints to thirty days from the date an order on the motion to remand is issued. Two new lawsuits were filed in California, one a putative class action in San Diego Superior Court on behalf of retail consumers of natural gas, and one in Alameda Superior Court on behalf of a cooperative of public agencies engaged in the retail purchase of natural gas. The actions are virtually identical to the Municipal Lawsuits, and the defendants include CMS Energy, CMS MST, Cantera Natural Gas, and Cantera Gas Company. More of such "copycat" actions may follow. CMS Energy and the other CMS defendants will defend themselves vigorously but cannot predict the outcome of these matters. LEONARD FIELD DISPUTE Pursuant to a Consent Judgment entered in Oakland County, Michigan Circuit Court in September 2001, CMS Gas Transmission had 18 months to extract approximately one bcf of pipeline quality natural gas held in the Leonard Field in Addison Township. The Consent Judgment provided for an extension of that period upon certain circumstances. CMS Gas Transmission has complied with the requirements of the Consent Judgment. Addison Township filed a lawsuit in Oakland County Circuit Court against CMS Gas Transmission in February 2004 alleging the Leonard Field was discharging odors in violation of the Consent Judgment. Pursuant to a Stipulated Order entered April 1, 2004, CMS Gas Transmission agreed to certain undertakings to address the odor complaints and further agreed to temporarily cease operations at the Leonard Field during the month of April 2004, the last month provided for in the Consent Judgment. Also, Addison Township was required to grant CMS Gas Transmission an extension to withdraw its natural gas if certain conditions were met. Addison Township denied CMS Gas Transmission's request for an extension on April 5, 2004. CMS Gas Transmission is pursuing its legal remedies and filed a complaint against Addison Township in June 2004. Addison Township has filed a counterclaim alleging CMS Gas Transmission has failed to remove certain equipment from the Leonard Field and that odor discharges have resulted in a diminution in surrounding property values and consequently a loss in property tax revenues. CMS Gas Transmission cannot predict the outcome of this matter, and unless an extension is provided, it will be unable to extract approximately 500,000 mcf of gas remaining in the Leonard Field. CO-4 CMS ENERGY AND CONSUMERS ERISA LAWSUITS CMS Energy is a named defendant, along with Consumers, CMS MST, and certain named and unnamed officers and directors, in two lawsuits brought as purported class actions on behalf of participants and beneficiaries of the CMS Employees' Savings and Incentive Plan (the "Plan"). The two cases, filed in July 2002 in United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended consolidated complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge issued an opinion and order dated March 31, 2004 in connection with the motions to dismiss filed by CMS Energy, Consumers, and the individuals. The judge dismissed certain of the amended counts in the plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims in the complaint. CMS Energy, Consumers, and the individual defendants filed answers to the amended complaint on May 14, 2004. A trial date has not been set, but is expected to be no earlier than late in 2005. CMS Energy and Consumers will defend themselves vigorously but cannot predict the outcome of this litigation. SECURITIES CLASS ACTION LAWSUITS Beginning on May 17, 2002, a number of securities class action complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates. The complaints were filed as purported class actions in the United States District Court for the Eastern District of Michigan, by shareholders who allege that they purchased CMS Energy's securities during a purported class period. The cases were consolidated into a single lawsuit and an amended and consolidated class action complaint was filed on May 1, 2003. The consolidated complaint contains a purported class period beginning on May 1, 2000 and running through March 31, 2003. It 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. The judge issued an opinion and order dated March 31, 2004 in connection with various pending motions, including plaintiffs' motion to amend the complaint and the motions to dismiss the complaint filed by CMS Energy, Consumers, and other defendants. The judge directed plaintiffs to file an amended complaint under seal and ordered an expedited hearing on the motion to amend, which was held on May 12, 2004. At the hearing, the judge ordered plaintiffs to file a Second Amended Consolidated Class Action complaint deleting Counts III and IV relating to purchasers of CMS PEPS, which the judge ordered dismissed with prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS Energy, Consumers, and the individual defendants filed new motions to dismiss on June 21, 2004. A hearing on those motions occurred on August 2, 2004 and the judge has taken the matter under advisement. CMS Energy, Consumers, and the individual defendants will defend themselves vigorously but cannot predict the outcome of this litigation. ENVIRONMENTAL MATTERS CMS Energy, Consumers and 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, CMS Energy and Consumers believe that it is unlikely that these actions, individually or in total, will have a material adverse effect on their financial condition. See CMS CO-5 Energy's and Consumers' MANAGEMENT'S DISCUSSION AND ANALYSIS and CMS Energy's and Consumers' CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. ITEM 5. OTHER INFORMATION A shareholder who wishes to submit a proposal for consideration at the CMS Energy 2005 Annual Meeting pursuant to the applicable rules of the SEC must send the proposal to reach CMS Energy's Corporate Secretary on or before December 24, 2004. In any event if CMS Energy has not received written notice of any matter to be proposed at that meeting by March 9, 2005, the holders of the proxies may use their discretionary voting authority on any such matter. The proposals should be addressed to: Corporate Secretary, CMS Energy, One Energy Plaza, Jackson, Michigan 49201. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) LIST OF EXHIBITS (31)(a) CMS Energy Corporation's certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(b) CMS Energy Corporation's certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(c) Consumers Energy Company's certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(d) Consumers Energy Company's certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (32)(a) CMS Energy Corporation's certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (32)(b) Consumers Energy Company's certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (b) REPORTS ON FORM 8-K CMS ENERGY During the third quarter of 2004, CMS Energy filed or furnished the following Current Reports on Form 8-K: - 8-K furnished on August 5, 2004 covering matters pursuant to Item 12, Results of Operations and Financial Condition (including a Summary of Consolidated Earnings, Summarized Comparative Balance Sheets, Summarized Statements of Cash Flows, and a Summary of Consolidated Earnings - Reconciliations of GAAP Net Income (Loss) to Non-GAAP Ongoing Net Income); - 8-K filed on August 20, 2004 covering matters pursuant to Item 5, Other Events; - 8-K filed on August 31, 2004 covering matters pursuant to Item 2.01, Completion of Acquisition or Disposition of Assets; and CO-6 - 8-K filed on September 1, 2004 covering matters pursuant to Item 5.02, Departure of Directors of Principal Officers; Election of Directors; Appointment of Principal Officers CONSUMERS During the third quarter of 2004, Consumers filed or furnished the following Current Reports on Form 8-K: - 8-K furnished on August 5, 2004 covering matters pursuant to Item 12, Results of Operations and Financial Condition (including a Summary of Consolidated Earnings, Summarized Comparative Balance Sheets, Summarized Statements of Cash Flows, and a Summary of Consolidated Earnings - Reconciliations of GAAP Net Income (Loss) to Non-GAAP Ongoing Net Income); - 8-K filed on August 20, 2004 covering matters pursuant to Item 5, Other Events; and - 8-K filed on September 1, 2004 covering matters pursuant to Item 5.02, Departure of Directors of Principal Officers; Election of Directors; Appointment of Principal Officers CO-7 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiary. CMS ENERGY CORPORATION (Registrant) Dated: November 4, 2004 By: /s/ Thomas J. Webb ---------------------------------- Thomas J. Webb Executive Vice President and Chief Financial Officer CONSUMERS ENERGY COMPANY (Registrant) Dated: November 4, 2004 By: /s/ Thomas J. Webb ----------------------------------- Thomas J. Webb Executive Vice President and Chief Financial Officer CO-8 EXHIBIT INDEX
EX. NO. DESCRIPTION ------ ----------- (31)(a) CMS Energy Corporation's certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(b) CMS Energy Corporation's certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(c) Consumers Energy Company's certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (31)(d) Consumers Energy Company's certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (32)(a) CMS Energy Corporation's certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (32)(b) Consumers Energy Company's certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002