10-Q 1 k85072e10vq.txt QUARTERLY REPORT FOR THE PERIOD ENDED 03/31/2004 ================================================================================ 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 MARCH 31, 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 April 30, 2004: CMS ENERGY CORPORATION: CMS Energy Common Stock, $.01 par value 163,544,282 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 MARCH 31, 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 the MCV Partnership and the FMLP....................................... CMS - 2 Forward-Looking Statements and Risk Factors............................................. CMS - 2 Results of Operations................................................................... CMS - 4 Critical Accounting Policies............................................................ CMS - 7 Capital Resources and Liquidity......................................................... CMS - 19 Outlook................................................................................. CMS - 23 New Accounting Standards................................................................ CMS - 34 Consolidated Financial Statements Consolidated Statements of Income (Loss)................................................ CMS - 38 Consolidated Statements of Cash Flows................................................... CMS - 40 Consolidated Balance Sheets............................................................. CMS - 42 Consolidated Statements of Common Stockholders' Equity.................................. CMS - 44 Condensed Notes to Consolidated Financial Statements: 1. Corporate Structure and Accounting Policies........................................ CMS - 45 2. Discontinued Operations, Other Asset Sales, Impairments, and Restructuring......... CMS - 47 3. Uncertainties...................................................................... CMS - 51 4. Financings and Capitalization...................................................... CMS - 72 5. Earnings Per Share and Dividends................................................... CMS - 76 6. Financial and Derivative Instruments............................................... CMS - 77 7. Retirement Benefits................................................................ CMS - 82 8. Equity Method Investments.......................................................... CMS - 83 9. Reportable Segments................................................................ CMS - 84 10. Asset Retirement Obligations........................................................ CMS - 85 11. Implementation of New Accounting Standards.......................................... CMS - 86
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 FMLP....................................... CE - 2 Forward-Looking Statements and Risk Factors............................................. CE - 2 Results of Operations................................................................... CE - 3 Critical Accounting Policies............................................................ CE - 7 Capital Resources and Liquidity......................................................... CE - 15 Outlook................................................................................. CE - 19 New Accounting Standards................................................................ CE - 29 Consolidated Financial Statements Consolidated Statements of Income....................................................... CE - 31 Consolidated Statements of Cash Flows................................................... CE - 32 Consolidated Balance Sheets............................................................. CE - 34 Consolidated Statements of Common Stockholder's Equity.................................. CE - 36 Condensed Notes to Consolidated Financial Statements: 1. Corporate Structure and Accounting Policies......................................... CE - 38 2. Uncertainties....................................................................... CE - 41 3. Financings and Capitalization....................................................... CE - 57 4. Financial and Derivative Instruments................................................ CE - 59 5. Retirement Benefits................................................................. CE - 64 6. Asset Retirement Obligations........................................................ CE - 65 7. Implementation of New Accounting Standards.......................................... CE - 66 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 - 5 Item 6. Exhibits and Reports on Form 8-K......................................................... CO - 5 Signatures....................................................................................... CO - 7
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 CMS Oil and Gas......................... CMS Oil and Gas Company, formerly a subsidiary of Enterprises CMS Pipeline Assets..................... CMS Enterprises pipeline assets in Michigan and Australia
4 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 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 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 Exchange Act............................ Securities Exchange Act of 1934, as amended FASB.................................... Financial Accounting Standards Board 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
5 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. 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. 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 holds a 50 percent ownership interest LNG..................................... Liquefied natural gas Ludington............................... Ludington pumped storage plant, jointly owned by Consumers and Detroit Edison Marysville.............................. CMS Marysville Gas Liquids Company, a Michigan corporation and a 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 METC.................................... Michigan Electric Transmission Company, formerly a subsidiary of Consumers Energy and now an indirect subsidiary of Trans-Elect
6 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 Panhandle Eastern Pipe Line or 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 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
7 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 ROA..................................... Retail Open Access RTO..................................... Regional Transmission Organization Rouge................................... Rouge Steel Industries SCP..................................... Southern Cross Pipeline in Australia, in which CMS Gas Transmission holds a 45 percent ownership interest SEC..................................... U.S. Securities and Exchange Commission Securitization.......................... A financing method authorized by statute and approved by the MPSC which allows a utility to sell its right to receive a portion of the rate payments received from its customers for the repayment of Securitization bonds issued by a special purpose entity affiliated with such utility SENECA.................................. Sistema Electrico del Estado Nueva Esparta, C.A., a subsidiary of Enterprises SERP.................................... Supplemental Executive Retirement Plan SFAS.................................... Statement of Financial Accounting Standards SFAS No. 5.............................. SFAS No. 5, "Accounting for Contingencies" SFAS No. 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. 106............................ SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" 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. 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"
8 SFAS No. 150............................ SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" 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 forty percent interest TEPPCO.................................. Texas Eastern Products Pipeline Company, LLC 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) Trusts accounts established to specifically set aside employer contributed assets to pay for future expenses of the OPEB plan
9 (This page intentionally left blank) 10 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 subsidiaries, is engaged in domestic and international diversified energy businesses including: independent power production; natural gas transmission, storage and processing; and energy services. 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, and other energy services. Our businesses are affected by weather, especially during the key 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 strategy involves rebuilding our balance sheet and refocusing on our core strength: superior utility operation. 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 other electric suppliers without receiving compensation for stranded costs caused by the lost sales. As of April 2004, we lost 823 MW or 10 percent of our electric business to these alternative electric suppliers. We expect the loss to grow to over 1,100 MW in 2004. 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 work cooperatively with the MPSC to resolve this issue. Further, higher natural gas prices have harmed the economics of the MCV and we are seeking approval from the MPSC to change the way in which the facility is used. Our proposal would reduce gas consumption by an estimated 30 to 40 bcf per year while improving the MCV'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 critical for our shareowners and customers. We also are focused on further reducing our business risk and leverage, while growing the equity base of our company. Much of our asset sales program is complete; we are focused on selling the remaining businesses that are not strategic to us. This creates volatility in earnings as we recognize foreign currency translation account losses at the time of sale, but it is the right strategic direction for our company. In April 2004, we and our partners sold the 2,000-megawatt 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 CMS-1 CMS ENERGY CORPORATION project equity. Our gross proceeds were about $54 million and are subject to closing adjustments and transaction costs. Finally, we are working to resolve outstanding litigation that stemmed from energy trading and gas index price reporting activities in 2001 and earlier. Doing so will permit us to devote more attention to improving business growth. In March 2004, the SEC imposed a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. 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. The result of these efforts 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 quarter ended March 31, 2003, as presented in this Form 10-Q, have been restated for the following matters that were previously disclosed in Note 19, Quarterly Financial and Common Stock Information (Unaudited), in our 2003 Form 10-K: - 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, and - certain derivative accounting corrections at our equity affiliates, which were reflected in our 2003 Form 10-K. 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 their assets, liabilities, and activities into our financial statements for the first time as of and for the quarter ended March 31, 2004. The MCV Partnership and the FMLP were previously reported as equity method investments. Therefore, the consolidation of these entities had no impact on our consolidated net loss. 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: - the efficient sale of non-strategic or under-performing domestic or international assets and discontinuation of certain operations, CMS-2 CMS ENERGY CORPORATION - capital and financial market conditions, including the current price of CMS Energy Common Stock and the effect on the Pension Plan, interest rates and 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, - security 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, - ability to access the capital markets successfully, - international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments, - adverse regulatory or legal decisions, including environmental laws and regulations, - 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, and proposals by the FERC to change the way it currently lets our subsidiaries and other public utilities and natural gas companies interact with each other, - energy markets, including the timing and extent of unanticipated 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, - 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 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, CMS-3 CMS ENERGY CORPORATION - 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 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 CMS Energy's business plan focuses on strengthening CMS Energy's balance sheet and improving financial liquidity through debt reduction and aggressive cost management. The on-going asset sales program's objectives are to generate cash to reduce debt, reduce business risk and provide for more predictable future earnings. This program encompasses the sale of non-strategic and under-performing assets, the proceeds of which are being used primarily to reduce debt. CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for per share amounts) ------------------------------------------------------------------------------ Restated Three months ended March 31 2004 2003 Change --------------------------- ------ ------ ------ Net Income (Loss) $ (11) $ 82 $ (93) Basic Earnings (Loss) Per Share $(0.07) $ 0.57 $(0.64) Diluted Earnings (Loss) Per Share $(0.07) $ 0.52 $(0.59) ------ ------ ------ Electric Utility $ 45 $ 51 $ (6) Gas Utility 55 54 1 Enterprises (61) 21 (82) Corporate Interest and Other (48) (51) 3 Discontinued Operations (2) 31 (33) Accounting Changes - (24) 24 ------ ------ ------ CMS Energy Net Income (Loss) $ (11) $ 82 $ (93) ====== ====== ======
For the three months ended March 31, 2004, CMS Energy's net loss was $11 million, compared to $82 million of net income for the three months ended March 31, 2003. The $93 million change reflects: - $81 million after-tax impairment charge on our Loy Yang investment. The impairment charge was recorded in connection with the sale of Loy Yang which was completed in April 2004, - the absence of earnings in discontinued operations from Panhandle and other businesses sold in prior periods, and - the reduction in electricity revenue resulting primarily from the continuing switch by industrial customers to alternative suppliers as allowed by the Customer Choice Act. For additional details, see "Electric Utility Results of Operations" within this section. These losses were partially offset by: CMS-4 CMS ENERGY CORPORATION - the exclusion in 2004 of a $24 million charge in 2003 that resulted from a cumulative effect of changes in accounting, and - income of $8 million (net of tax) in 2004 reflecting a settlement agreement that DIG and CMS MST entered into with Ford and Rouge. ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions --------------------------------------------------------------------------- March 31 2004 2003 Change -------- ---- ---- ------ Three months ended $ 45 $ 51 $ (6) ==== ==== ==== Reasons for the change: Electric deliveries $(10) Power supply costs and related revenue (6) Other operating expenses and non-commodity revenue 10 General taxes 4 Fixed charges (6) Income taxes 2 ---- Total change $ (6) ====
ELECTRIC DELIVERIES: Electric deliveries, including transactions with other wholesale marketers, other electric utilities, and customers choosing alternative suppliers increased 0.3 billion kWh or 3.6 percent in the first quarter of 2004 compared to 2003. Despite increased electric deliveries, electric delivery revenue decreased in the first quarter of 2004 versus 2003. This revenue decrease primarily reflects tariff revenue reductions that began January 1, 2004. The tariff revenue reductions were equivalent to the Big Rock nuclear decommissioning surcharge in effect when our electric retail rates were frozen from June 2000 through December 31, 2003. The tariff revenue reduction decreased electric delivery revenue by $9 million in the first quarter of 2004 versus 2003, and is expected to decrease electric delivery revenues $35 million in 2004 versus 2003. The reduction in electric delivery revenue for the first quarter 2004 versus 2003 also reflects the impact of customers switching to alternative electric suppliers as allowed by the Customer Choice Act. Although deliveries to the sector of customers choosing an alternative supplier has grown significantly from the same period in 2003, the margin on these sales is substantially less than if we had supplied the generation. POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost rate of recovery 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 revenues had been less than actual power supply costs, the impact 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 revenues are in excess of actual power supply costs, this former benefit is reserved for possible future refund. This change in the treatment of excess CMS-5 CMS ENERGY CORPORATION power supply revenues over power supply costs decreased 2004 versus 2003 first quarter operating income. OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In the first quarter of 2004, other operating expenses decreased $2 million and non-commodity revenue increased $8 million versus 2003. The increase in non-commodity revenue relates primarily to interest income recognized in relation to capital expenditures in excess of depreciation as allowed by the Customer Choice Act. The decrease in operating expenses reflects a reduction in nuclear operating and maintenance expense in 2004 compared to the same period in 2003 that included a scheduled refueling outage at the Palisades nuclear facility. GENERAL TAXES: In the first quarter of 2004, general taxes decreased from the same period in 2003 due primarily to reductions in MSBT expense. FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004 versus the same period in 2003 due to higher average debt levels, partially offset by a 41 basis point reduction in the average interest rate. INCOME TAXES: In the first quarter of 2004, income taxes decreased versus the same period in 2003 due primarily to lower earnings by the electric utility. GAS UTILITY RESULTS OF OPERATIONS
In Millions ----------------------------------------------------------------------------- March 31 2004 2003 Change -------- ---- ---- ------ Three months ended $ 55 $ 54 $ 1 ==== ==== ====== Reasons for the change: Gas deliveries $ (14) Gas rate increase 9 Gas wholesale and retail services and other gas revenues 2 Operation and maintenance (4) General taxes, depreciation, and other income 6 Fixed charges (3) Income taxes 5 ------ Total change $ 1 ======
GAS DELIVERIES: For the first quarter 2004 versus the same period in 2003, gas deliveries, including miscellaneous transportation, decreased 7 bcf or 4 percent versus 2003. Deliveries decreased during the first quarter of 2004 due primarily 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, first quarter 2004 gas revenues increased compared to the same period in 2003. CMS-6 CMS ENERGY CORPORATION GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: Gas wholesale and retail services and other gas revenues increased for the period ended March 31, 2004 versus the same period in 2003. This increase relates primarily to increases in gas transportation and storage revenues and late payment fees. In 2003, we reserved $11 million for a settlement agreement associated with the 2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003 through February 2004, at Consumers' authorized rate of return, increased the cost of the settlement by $1 million. In March 2004, the MPSC approved this settlement agreement in the amount we had reserved. Neither the prior year reservation, nor the current year final MPSC settlement had any effect on earnings in the first quarter of 2004 versus the same period in 2003. OPERATION AND MAINTENANCE: In the first quarter 2004 versus 2003, operation and maintenance expenses increased due to increases in health care costs and additional expenditures on safety, reliability, and customer service. GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In the first quarter 2004 versus 2003, the net change in general tax expense, depreciation expense, and other income increased operating income primarily because of decreases in depreciation rates authorized by the MPSC's December 2003 interim rate order. FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004 versus the same period in 2003 due to higher average debt levels, partially offset by a 41 basis point reduction in the average interest rate. INCOME TAXES: Income tax expense decreased in the period ended March 31, 2004 versus the same period in 2003. This reduction was attributable primarily to the income tax treatment of items related to plant, property and equipment as required by past MPSC rulings. ENTERPRISES RESULTS OF OPERATIONS For the three months ended March 31, 2004, Enterprises' net loss was $61 million, compared to $21 million of net income for the comparable period in 2003. The $82 million change reflects primarily an asset impairment charge related to the sale of Loy Yang, which was completed in April 2004. For additional details, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. OTHER RESULTS OF OPERATIONS For the three months ended March 31, 2004, corporate interest and other net expenses were $48 million compared to $51 million for the comparable period in 2003. The reduction was primarily the result of an $8 million benefit from the reversal of a currency translation adjustment associated with Loy Yang, partially offset by an increase in interest expense. OTHER: In 2003, we sold Panhandle and other businesses as we continued to implement our utility-plus strategy. The decreased earnings of $33 million in discontinued operations are a result of the sale of income producing assets. For more information, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. CRITICAL ACCOUNTING POLICIES The following accounting policies are important to an understanding of our results and financial condition and should be considered an integral part of our MD&A: CMS-7 CMS ENERGY CORPORATION - use of estimates in accounting for long-lived assets, equity method investments, and contingencies, - accounting for financial and derivative instruments, - accounting for international operations and foreign currency, - accounting for the effects of industry regulation, - accounting for pension and postretirement benefits, - 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 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 $15.117 billion at March 31, 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 CMS-8 CMS ENERGY CORPORATION 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 the financial statements. In March 2004, we reduced the carrying amount of our investment in Loy Yang to reflect its fair value. For additional details on asset sales, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. We are still pursuing 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. Even though these assets have been identified for sale, 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 accruals for such contingencies based upon our assessment that the occurrence is probable and 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 power purchase agreement 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 power purchase agreement 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 power purchase agreement. 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. Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned in our coal plants and our operations and maintenance expenses. However, the MCV Partnership's CMS-9 CMS ENERGY CORPORATION costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years, while the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been affected adversely. 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 harmed. In February 2004, we filed a resource conservation plan 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 natural gas consumption 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 April 2004, the presiding ALJ at the MPSC held a pre-hearing conference regarding the resource conservation plan. The ALJ denied our request to establish a schedule that would have allowed consideration of the plan on an interim basis and established a review schedule that calls for a Proposal for Decision in September 2004 after which point the MPSC would consider the plan. We cannot predict if or when the MPSC will approve our resource conservation plan. 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 22 years and the MPSC's decision in 2007 or beyond related to limiting our recovery of capacity and fixed energy payments. Natural gas prices have been volatile historically. Presently, there is no consensus in the marketplace on the price or range of prices of natural gas in the short term or beyond the next five years. Even with an approved resource conservation plan, 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, see Note 3, Uncertainties, "Other Consumers Electric Uncertainties - The Midland Cogeneration Venture." 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 securities. 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 and 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 reported as regulatory liabilities. The fair value of these investments is determined from quoted market prices. Our debt securities are classified as held-to-maturity securities and are reported at cost. CMS-10 CMS ENERGY CORPORATION 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. The accounting for changes in the fair value of a derivative (that is, gains or losses) is reported either in earnings or accumulated other comprehensive income depending on whether the derivative qualifies for special hedge accounting treatment. For additional details on the accounting policies for derivative instruments, see Note 6, Financial and Derivative Instruments. 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 options, gas fuel contracts containing volume optionality, fixed priced weather-based gas supply call options, fixed price gas supply call and put options, gas futures, gas and power swaps, and forward purchases and sales. 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 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. If an active market develops 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. 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, volatilities, interest rates, and exercise periods. Changes in forward prices or volatilities could change significantly the calculated fair value of certain contracts. At March 31, 2004, we assumed a market-based interest rate of 1 percent (a rate that is not significantly different than the LIBOR rate) and volatility rates ranging between 55 percent and 146 percent to calculate the fair value of our electric and gas options. At March 31, 2004, we assumed market-based interest rates ranging between 1.09 percent and 2.7 percent and volatility rates ranging between 23 percent and 38 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 trading contracts that are directly related to activities considered to be an integral part of CMS Energy's ongoing operations. The intent of holding these energy contracts is to optimize the performance of CMS Energy-owned generating assets and to fulfill contractual obligations. CMS-11 CMS ENERGY CORPORATION CMS ERM accounts for power and gas trading contracts 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. The following tables provide a summary of the fair value of our energy trading contracts as of March 31, 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 (7) Other changes in fair value (b) 10 ---- Fair value of contracts outstanding as of March 31, 2004 $ 15 ====
(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. CMS-12 CMS ENERGY CORPORATION
Fair Value of Contracts at March 31, 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 $ (27) $ - $ (10) $ (17) $ - Prices based on models and other valuation methods 42 10 17 15 - ------ ------ ------ ------ ---- Total $ 15 $ 10 $ 7 $ (2) $ - ====== ====== ====== ====== ====
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 "Equity 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 ------------------------------------------------------------------------------- March 31, 2004 December 31, 2003 -------------- ----------------- Variable-rate financing - before tax annual earnings exposure $ 1 $ 1 Fixed-rate financing - potential loss in fair value (a) 241 242 ====== =======
(a) Fair value exposure could only be realized if we repurchased all of our fixed-rate financing. CMS-13 CMS ENERGY CORPORATION As discussed in "Electric Utility Business Uncertainties - Competition and Regulatory Restructuring - Securitization" within this MD&A, we have filed an application with the MPSC to securitize certain expenditures. Upon final approval, we intend to use the proceeds from the Securitization to retire higher-cost debt, which could include a portion of our current fixed-rate debt. We do not believe that any adverse change in debt price and interest rates would have a material adverse effect on either our consolidated financial position, results of operations, or cash flows. 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 used 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. Electric call options give us the right, but not the obligation, to purchase electricity at predetermined fixed prices. Weather-based gas supply call options, along with the gas supply call and put options, are used to purchase reasonably priced gas supply. Gas supply call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Gas supply put options give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices. At March 31, 2004, we only held gas supply call and 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, thus, are treated as derivative instruments. Also, the MCV Partnership enters into natural gas futures contracts 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. Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions -------------------------------------------------------------------------------- March 31, December 31, 2004 2003 --------- ------------ Potential reduction in fair value: Gas supply call and put option contracts $ 12 $ 1 Derivative contracts associated with Consumers' investment in the MCV Partnership: Gas fuel contracts 24 N/A Gas fuel futures 25 N/A
During the first quarter of 2004, we entered into additional gas supply call and put option contracts. As a result, the potential reduction in the fair value increased from December 31, 2003 as shown in the table above. 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 further discussed in Note 11, Implementation of New Accounting Standards. CMS-14 CMS ENERGY CORPORATION 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, and swap contracts. The prices of these energy commodities can fluctuate because of, among other things, changes in the supply of and demand for those commodities. Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions ------------------------------------------------------------------------------ March 31, 2004 December 31, 2003 -------------- ----------------- Potential reduction in fair value: Gas-related swaps and forward contracts $ 3 $ 3 Electricity-related forward contracts 2 2 Electricity-related call option contracts 3 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 typically 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. 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 March 31, 2004, we had no foreign exchange hedging contracts outstanding. As of March 31, 2004, the total foreign currency translation adjustment was a net loss of $313 million that included a net hedging loss of $25 million related to settled contracts. Equity 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 and 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 reported as regulatory liabilities. 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 ------------------------------------------------------------------------------ March 31, 2004 December 31, 2003 -------------- ----------------- Potential reduction in fair value: Nuclear decommissioning investments $ 56 $ 57 Other available for sale investments 7 7 === ===
For additional details on market risk and derivative activities, see Note 6, Financial and Derivative Instruments. CMS-15 CMS ENERGY CORPORATION INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY We have investments in energy-related projects throughout 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 the Consolidated Balance Sheets as "Foreign Currency Translation." As of March 31, 2004, cumulative foreign currency translation decreased stockholders' equity by $313 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. In March 2004, we recognized the foreign currency translation loss in earnings as a component of the Loy Yang impairment of approximately $81 million, recorded as a result of the sale of Loy Yang that was completed in April 2004. At March 31, 2004, the net foreign currency gain due to the exchange rate of the Australian dollar recorded in the Foreign Currency Translation component of stockholders' equity using an exchange rate of 1.328 Australian dollars per U.S. dollar was $8 million. This foreign currency translation gain relates primarily to our SCP and Parmelia investments. Argentina: 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 Argentina 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, political risk insurance, and the eventual sale of these assets. At March 31, 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 2.86 pesos per U.S. dollar was $262 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 that were no longer considered permanent. CMS-16 CMS ENERGY CORPORATION 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 outlined 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 reduce 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 are inversely correlated with the losses and gains, respectively, on the assets and liabilities being hedged. 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 March 31, 2004, we had $1.125 billion recorded as regulatory assets and $1.497 billion recorded as regulatory liabilities. For additional details on industry regulation, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." 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 certain employees hired after June 30, 2003. We use SFAS No. 87 to account for pension costs. 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. CMS-17 CMS ENERGY CORPORATION The following table provides an estimate of our pension expense, OPEB expense, and cash contributions for the next three years:
Expected Costs In Millions --------------------------------------------------- Pension Expense OPEB Expense Contributions --------------- ------------ ------------- 2004 $ 21 $ 55 $ 129 2005 55 63 118 2006 75 59 109 ==== ==== =====
Actual future pension expense 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 March 31, 2004, we have a prepaid pension asset of $403 million recorded 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 expense 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 expense for 2004 by $4 million. The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that was signed into law in December 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We are continuing to defer recognizing the effects of the Act in our 2004 financial statements, as permitted by FASB Staff Position No. 106-b. When accounting guidance is issued, our retiree health benefit obligation may be adjusted. 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, Accounting for Asset Retirement Obligations, 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 a regulatory asset and liability 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 the asset retirement obligation is incurred, such as 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. There is a low probability of a retirement date, so no liability has been recorded for these assets. No liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for CMS-18 CMS ENERGY CORPORATION Palisades and Big Rock are based on decommissioning studies that are based largely on 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 balance sheet. 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, 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. Recently, 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 CMS-19 CMS ENERGY CORPORATION have requested advance payment or other forms of assurances, including margin calls, in connection with maintenance of ongoing deliveries of gas and electricity. In 2003, we had debt maturities and capital expenditures that required substantial amounts of cash. We were also subject to liquidity demands of various commercial commitments, such as guarantees, indemnities, and letters of credit. As a result, we executed a financial improvement plan to address these critical liquidity issues. In 2003, we suspended payment of the common stock dividend and increased our efforts to reduce operating expenses and capital expenditures. We continued to sell non-strategic assets and we used the proceeds to reduce debt. Finally, we explored financing opportunities, such as refinancing debt, issuing new debt and preferred equity, and negotiating private placement debt. Together, all of these steps enabled us to meet our liquidity demands. In 2004, we are continuing to monitor our operating expenses and capital expenditures, evaluate market conditions for financing opportunities, and sell assets that are not consistent with our strategy. Execution of our asset sales program is expected to generate positive cash flow in 2004, however, it is not critical to the maintenance of sufficient corporate liquidity. Further, we do not anticipate paying common stock dividends in the foreseeable future. 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. 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 Consolidated cash needs are met by our operating, investing, and financing activities. At March 31, 2004, $767 million consolidated cash was on hand which includes $216 million of restricted cash. For additional details on 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 proceeds from asset sales. For the first three months of 2004, Consumers paid $78 million in common stock dividends and Enterprises paid $80 million in common stock dividends and other distributions to CMS Energy. SUMMARY OF CASH FLOWS:
In Millions ---------------------------------------------------- Three months ended March 31 2004 2003 --------------------------- ---- ---- Net cash provided by (used in): Operating activities $ 235 $ 415 Investing activities (115) (61) Financing activities (266) (50) Effect of exchange rates on cash (9) 1 ----- ----- Net increase (decrease) in cash and temporary cash investments $(155) $ 305 ===== =====
CMS-20 CMS ENERGY CORPORATION OPERATING ACTIVITIES: For the three months ended March 31, 2004, net cash provided by operating activities decreased $180 million due to a greater decrease in accounts payable and accrued expenses of $44 million and a greater increase in accounts receivable and accrued revenue of $189 million primarily due to lower sales of accounts receivable resulting from our improved liquidity. This change was offset by a greater decrease in inventories of $125 million primarily resulting from gas sales at higher prices combined with lower volumes of gas purchased. INVESTING ACTIVITIES: For the three months ended March 31, 2004, net cash used in investing activities increased $54 million due primarily to a decrease in asset sale proceeds of $92 million, offset by a greater decrease in capital expenditures of $43 million. FINANCING ACTIVITIES: For the three months ended March 31, 2004, net cash used in financing activities increased $216 million due primarily to a decrease of $218 million in net proceeds from borrowings. For additional details on long-term debt activity, see Note 4, Financings and Capitalization. OBLIGATIONS AND COMMITMENTS Our total contractual obligations as of March 31, 2004 are shown in the following table.
Contractual Obligations In Millions --------------------------------------------------------------------------- Payments Due ------------------------------------------------------ Total 2004 2005 2006 2007 2008 Beyond ------- ------ ------- ------- ------- ------- ------- On-balance sheet: Long-term debt $ 6,678 $ 362 $ 785 $ 546 $ 545 $ 1,050 $ 3,390 Long-term debt - related parties 684 - - - - - 684 Capital lease obligations 372 44 31 27 26 26 218 ------- ------- ------- ------ ------- ------- ------- Total on-balance sheet $ 7,734 $ 406 $ 816 $ 573 $ 571 $ 1,076 $ 4,292 ------- ------- ------- ------ ------- ------- ------- Off-balance sheet: Non-recourse debt $ 2,716 $ 269 $ 77 $ 411 $ 65 $ 67 $ 1,827 Operating leases 77 11 10 10 9 7 30 Long-term service agreements 219 9 12 19 13 12 154 Unconditional purchase obligations 7,637 1,599 1,161 715 517 442 3,203 ------- ------- ------- ------ ------- ------- ------- Total off-balance sheet $10,649 $ 1,888 $ 1,260 $1,155 $ 604 $ 528 $ 5,214 ======= ======= ======= ====== ======= ======= =======
CMS-21 CMS ENERGY CORPORATION For additional details, see Note 3, Uncertainties, and Note 4, Financings and Capitalization. REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers issues short and long-term securities under the FERC authorization. For additional details of Consumers' existing authorization, see Note 4, Financings and Capitalization. LONG-TERM DEBT: Details on long-term debt are presented in Note 4, Financings and Capitalization. SHORT-TERM FINANCINGS: At March 31, 2004, CMS Energy has $190 million available, Consumers has $376 million available, and the MCV Partnership has $50 million available in short-term credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. For additional details, see Note 4, Financings and Capitalization. CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of the leased portion of the MCV Partnership facility, leased service vehicles, and leased office furniture. The full obligation of our leases could become due in the event of lease payment default. OFF-BALANCE SHEET ARRANGEMENTS: We use off-balance sheet arrangements in the normal course of business. Our off-balance sheet arrangements include: - operating leases, - non-recourse debt, - long-term service agreements, - sale of accounts receivable, and - unconditional purchase obligations. Operating Leases: Our leases of railroad cars, certain vehicles, and miscellaneous office equipment are accounted for as operating leases. Non-recourse Debt: Our share of unconsolidated debt associated with partnerships and joint ventures in which we have a minority interest is non-recourse. Long-term Service Agreements: These obligations of the MCV Partnership represent the cost of the current MCV Facility maintenance service agreements and cost of spare parts. 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. Unconditional Purchase Obligations: Long-term contracts for purchase of commodities and services are unconditional purchase obligations. These obligations represent operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include: - natural gas, - electricity, - coal purchase contracts and their associated cost of transportation, and - electric transmission. Included in unconditional purchase obligations are long-term power purchase agreements with various generating plants. These contracts require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $9 million per month during 2004. If a plant is not available to deliver electricity, we are not obligated to make the capacity payments to the plant CMS-22 CMS ENERGY CORPORATION for that period of time. For additional details on power supply costs, see "Electric Utility Results of Operations" within this MD&A and Note 3, Uncertainties, "Consumers' Electric Utility Rate Matters - Power Supply Costs." COMMERCIAL COMMITMENTS: Our commercial 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 March 31, 2004, expire as follows:
Commercial Commitments In Millions -------------------------------------------------------------------------------- Commitment Expiration ---------------------------------------------------------------- Total 2004 2005 2006 2007 2008 Beyond ------- ------- ------- ------- ------- ------- ------- Off-balance sheet: Guarantees $ 212 $ 6 $ 36 $ 4 $ - $ - $ 166 Indemnities 27 8 - - - - 19 Letters of Credit (a) 248 112 108 5 5 5 13 ------- ------- ------- ------- ------- ------- ------- Total $ 487 $ 126 $ 144 $ 9 $ 5 $ 5 $ 198 ======= ======= ======= ======= ======= ======= =======
(a) At March 31, 2004, we had $173 million of cash collateralized letters of credit. The cash that collateralizes the letters of credit is included in Restricted Cash on the Consolidated Balance Sheets. DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at March 31, 2004, Consumers had $397 million of unrestricted retained earnings available to pay common dividends. Covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. Consumers is also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. As of March 31, 2004, CMS Energy has received $78 million of common stock dividends from Consumers. Our $190 million revolving credit facility with banks, which expires in November 2004, contains provisions that prohibit us from paying dividends on our common stock. For additional details on the cap on common dividends payable during the current interim gas rate relief period, see Note 3, Uncertainties, "Consumers' Gas Utility Rate Matters - 2003 Gas Rate Case." OUTLOOK CORPORATE OUTLOOK During 2004, we are continuing to implement a utility-plus strategy that focuses on growing a healthy utility and divesting under-performing or other non-strategic assets. The strategy is designed to generate cash to pay down debt, reduce business risk, and provide for more predictable future operating revenues and earnings. Consistent with our utility-plus strategy, we are pursuing actively the sale of non-strategic and under-performing assets. Some of these assets are recorded at estimates of their current fair value. Upon the sale CMS-23 CMS ENERGY CORPORATION of these assets, the proceeds realized may be different from the recorded values if market conditions have changed. Even though these assets have been identified for sale, we cannot predict when, nor make any assurance that, these sales will occur. We anticipate that the cash proceeds from these sales, if any, will be used to retire existing debt. As we continue to implement our utility-plus strategy and further reduce our ownership of non-utility assets, 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. 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 abnormal 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 project electric deliveries to grow approximately two percent. This short-term outlook for 2004 assumes higher levels of manufacturing activity than in 2003 and normal weather conditions during the remainder of the year. 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: 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 being followed by the MPSC, - recovery of electric restructuring implementation costs, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer instead of an electric transmission owner-operator. CMS-24 CMS ENERGY CORPORATION Regulatory - effects of conclusions about the causes of the August 14, 2003 blackout, including exposure to liability, increased regulatory requirements, and new legislation, - successful implementation of initiatives to reduce exposure to purchased power price increases, - effects of potential performance standards payments, - effects of the FERC supply margin assessment 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 and coal, - pending litigation filed by PURPA qualifying facilities, - pending other litigation, and - potential rising pension costs due to market losses and lump sum payments. For additional details, see "Accounting for Pension and OPEB" within this MD&A. 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 $771 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 8.9 percent. As of March 31, 2004, we have incurred $469 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 2009. These expenditures include installing catalytic reduction technology on coal-fired electric plants. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost of these credits is estimated to average $8 million per year and 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 CMS-25 CMS ENERGY CORPORATION fines. The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which requires 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 required to reduce nitrogen oxide emissions 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, through the installation of flue gas desulfurization scrubbers and selective catalytic reduction units. 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. Several bills have been introduced in the United States Congress that would require carbon dioxide emissions reduction. We cannot predict whether any federal mandatory carbon dioxide emissions reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that emissions reduction rules come into legal 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 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 April 2004, alternative electric suppliers are providing 823 MW of generation supply to ROA customers. This amount represents 10 percent of our distribution load and an increase of 50 percent compared to April 2003. We anticipate this upward trend to continue and expect over 1,100 MW of generation supply to ROA customers in 2004. We cannot predict the total amount of electric supply load that may be lost to competitor suppliers. In February 2004, the MPSC issued an order on Detroit Edison's request for rate relief for costs associated with customers leaving under electric customer choice. The MPSC order allows Detroit Edison to implement a transition charge on ROA customers and eliminates securitization charge offsets. We are seeking similar recovery of Stranded Costs due to ROA customers leaving our system and are encouraged by this ruling. We cannot predict if or when the MPSC will approve implementation of a transition charge on our ROA customers. CMS-26 CMS ENERGY CORPORATION Securitization: In March 2003, we filed an application with the MPSC seeking approval to issue Securitization bonds. In June 2003, the MPSC issued a financing order authorizing the issuance of Securitization bonds in the amount of approximately $554 million. In July 2003, we filed for rehearing and clarification on a number of features in the financing order. In December 2003, the MPSC issued its order on rehearing, which rejected our requests for clarification and modification to the dividend payment restriction, failed to rule directly on the accounting clarifications requested, and remanded the proceeding to the ALJ for additional proceedings to address rate design. We filed testimony regarding the remanded proceeding in February 2004. The ALJ completed hearings in March 2004 and the MPSC decision is not anticipated before May 2004, but could be later. The financing order will become effective after our acceptance of a favorable MPSC order. Bonds will not be issued until resolution of any appeals. 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 adopted by the MPSC will be applied in a manner that will fully offset any associated margin loss. In 2002 and 2001, the MPSC issued orders finding that we experienced zero net Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous issues regarding the net Stranded Cost methodology in a way that would allow a reliable prediction of the level of Stranded Costs for future years. We currently are in the process of appealing these orders with the Michigan Court of Appeals and the Michigan Supreme Court. In March 2003, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2002, and for approval of a net Stranded Cost recovery charge. Our net Stranded Costs incurred in 2002, including the cost of money, are estimated to be $47 million with the issuance of Securitization bonds that include Clean Air Act investments, or $104 million without the issuance of Securitization bonds that include Clean Air Act investments. Once the MPSC issues a final financing order on Securitization, we will know the amount of our request for net Stranded Cost recovery for 2002. In April 2004, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2003, including the cost of money, in the amount of $106 million with the issuance of Securitization bonds that include Clean Air Act investments, or $165 million without the issuance of Securitization bonds that include Clean Air Act investments. Similar to the request that was granted by the MPSC for Detroit Edison, we also requested interim relief for 2002 and 2003 net Stranded Costs. We cannot predict how the MPSC will rule on our requests for the recoverability of Stranded Costs. Therefore, we have not recorded regulatory assets to recognize the future recovery of such costs. Implementation Costs: Since 1997, we have incurred significant costs to implement the Customer Choice Act. The Customer Choice Act allows electric utilities to recover the Act's implementation costs. The MPSC reviewed and granted deferred conditional recovery of certain of the implementation costs incurred through 2001, but has not yet authorized rates that would allow recovery. Our applications for $7 million of implementation costs for 2002 and $1 million for 2003 are currently pending approval by the MPSC. Included in the 2002 request is $5 million related to our former participation in the development of the Alliance RTO. As of March 31, 2004, implementation costs totaled $93 million, which includes $23 million associated with the cost of money. We believe the implementation costs and the associated cost of money are fully recoverable in accordance with the Customer Choice Act. Cash recovery from customers is expected to begin after rate cap periods CMS-27 CMS ENERGY CORPORATION expire. For additional information on rate caps, see "Rate Caps" within this section. In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision finding that the recovery of 1999 implementation costs is conditional and subject to later disallowance is unlawful. The case was remanded to the MPSC. The MPSC issued an order regarding the remanded proceeding that directed us to choose whether we prefer to recover our approved implementation costs through Securitization pursuant to the MPSC's final order in the Securitization proceeding or whether we would prefer to have recovery controlled by the remand proceeding. If the latter option was chosen, the MPSC indicated that it intended to authorize recovery of such implementation costs through the use of surcharges on all customer classes that coincide with the expiration of the Customer Choice Act rate caps. We chose recovery of the approved implementation costs through the use of surcharges and withdrew our request for approved implementation costs recovery from our Securitization proposal. The implementation costs withdrawn from the Securitization case were incurred for the years 1998 through 2000. In the filing we made electing recovery through separate surcharges, we requested approval of surcharges that would allow recovery of implementation costs incurred for the years 1998 through 2001. We requested that the Court of Appeals issue similar remand orders with respect to appeals of the MPSC orders addressing 2000 and 2001 implementation costs. We cannot predict the amounts the MPSC will approve as recoverable costs. Also, we are pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million in certain electric utility restructuring implementation costs related to our former participation in the development of the Alliance RTO, a portion of which has been expensed. In May 2003, the FERC issued an order denying the MISO's request for authorization to reimburse us. We appealed the FERC ruling at the United States Court of Appeals for the District of Columbia. We also requested that the MISO seek authorization to reimburse the METC for these development costs. The MISO filed this request but the FERC denied it. While we appeal the FERC's orders, we are also pursuing other potential means of recovery, such as recovery of Alliance RTO development costs at the MPSC. We cannot predict the outcome of the appeal process or the ultimate amount, if any, we will collect for Alliance RTO development costs. Security Costs: The Customer Choice Act allows for recovery of new and enhanced security costs, as a result of federal and state regulatory security requirements. All retail customers, except customers of alternative electric suppliers, would pay these charges. In April 2004, we filed a security cost recovery case with the MPSC for $25 million of cost that regulatory treatment has not yet been granted through other means. The costs are for enhanced security and insurance because of federal and state regulatory security requirements imposed after the September 11, 2001 terrorist attacks. We cannot predict how the MPSC will rule on our requests for the recoverability of security costs. 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 make it impossible for us to fully recover 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 assures 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. We estimate the recovery of increased power supply costs from CMS-28 CMS ENERGY CORPORATION large commercial and industrial customers to be approximately $30 million in 2004. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. The revenues received from the PSCR charge are also subject to subsequent reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of this filing. Decommissioning Surcharge: When our electric retail rates were frozen in June 2000, a nuclear decommissioning surcharge related to the decommissioning of Big Rock was included. In December 2000, funding of the Big Rock nuclear decommissioning trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. However, we continued to collect the equivalent to the Big Rock nuclear decommissioning surcharge consistent with the Customer Choice Act rate freeze through December 31, 2003. Collection of the surcharge stopped, effective January 1, 2004, when the electric rate freeze expired. Industrial Contracts: We entered into multi-year electric supply contracts with certain large industrial customers. The contracts provide electricity at specially negotiated prices, usually at a discount from tariff prices. The MPSC approved these special contracts totaling approximately 685 MW of load. Unless terminated or restructured, the majority of these contracts are in effect through 2005. As of March 31, 2004, contracts for 201 MW of load have terminated. Of the contracts that have terminated, 70 MW of load have gone to an alternative electric supplier and 131 MW of load have returned to bundled tariff rates. In January 2004, new special contracts for 91 MW, with the State of Michigan and three universities, were approved by the MPSC. Initial special contracts with Dow Corning and Hemlock Semi-Conductor were terminated in December 2003. New special contracts with Dow Corning and Hemlock Semi-Conductor for 101 MW received interim approval from the MPSC and are awaiting final approval. As of April 2004, our special contracts total approximately 580 MW of load. All new special contracts end by January 1, 2006. We cannot predict whether additional special contracts will be necessary, advisable, or approved. Transmission Sale: 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. We cannot predict whether the remaining open items will affect materially the sale proceeds previously recognized. 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. The financial impact of such proceedings, rulemaking, and trends are not quantifiable currently. In addition, we are evaluating whether or not there may be impacts on electric reliability associated with the outcomes of these various transmission related proceedings. For example, in April 2004, Commomwealth Edison Company received approval from the FERC to join into the PJM RTO effective May 1, 2004. This integration could create different patterns of flow and power within the Midwest area and affect adversely our ability to provide reliable service to our customers. CMS-29 CMS ENERGY CORPORATION 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. In December 2003, the MPSC issued an order requiring Michigan investor-owned utilities to file reports by April 1, 2004, on the status of the transmission and distribution lines used to serve their customers, including details on vegetation trimming practices in calendar year 2003. We complied with the MPSC's order. In February 2004, the Board of Trustees of the NERC approved recommendations to improve electric transmission reliability. In April 2004, the U.S. and Canadian Power System Outage Task Force released its final report on the causes and recommendations surrounding the blackout. The Task Force concluded that inadequate assessment of voltage instability and vulnerability by First Energy; inadequate communication between interconnected grid operators; and improper vegetation management, outside of our operating territory, were the key causes of the blackout. In addition to the NERC recommendations, the Task Force made 46 recommendations under the following captions: - institutional issues, - support for and strengthening of ongoing NERC initiatives, - physical and cyber security of North American bulk power systems, and - Canadian nuclear power sector operating procedures. Prompted by the Task Force findings, the MPSC issued an order requiring Michigan utilities and transmission companies to submit a report concerning relay settings on their systems by May 10, 2004. We intend to comply with the MPSC's request. Also, the FERC issued a vegetation management order requiring entities that own, operate, or control designated transmission facilities to report on their vegetation management practices by June 17, 2004. As defined by this particular FERC order, we have a limited amount of designated transmission facilities for reporting purposes pursuant to this order, including a total of six miles of high voltage lines located on or adjacent to some generating plant properties. Few of the recommendations above apply directly to us, since we are not a transmission operator. However, the above recommendations could result in increased transmission costs payable by transmission customers in the future and upgrades to our distribution system. The financial impacts of these recommendations are not quantifiable currently. For additional details and material changes relating to the rate matters and restructuring of the electric utility industry, see Note 3, Uncertainties, "Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric Utility Rate Matters." FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new market power screens to assess generation market power and modified measures to mitigate market power where it is found. The screens will apply to all initial market-based rate applications and reviews on an interim basis, which occur every three years. The effects of the modifications are not quantifiable currently. PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The standards relate to restoration after an outage, safety, and customer relations. Financial incentives and penalties are contained within the performance standards. An incentive is possible if all of the established performance standards have been exceeded for a calendar year. However, the performance standards do not contain an approved incentive mechanism; therefore, the value of such an incentive cannot be determined at this point. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. Year-end results for both 2002 and 2003 resulted in compliance with the acceptable level of performance as established by the approved standards. We are a member of an industry coalition that has appealed the customer credit CMS-30 CMS ENERGY CORPORATION portion of the performance standards to the Michigan Court of Appeals. We cannot predict the likely effects of the financial incentive or penalties, if any, on us, nor can we predict the outcome of the appeal. 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: - abnormal weather, - 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 Michigan Public Service Commission 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. 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: Environmental - potential environmental remediation costs at a number of sites, including sites formerly housing manufactured gas plant facilities. Regulatory - inadequate regulatory response to applications for requested rate increases, and - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, Other - potential rising pension costs due to market losses and lump sum payments as discussed in the "Critical Accounting Policies - Accounting for Pension and OPEB" section within this MD&A, - pipeline integrity maintenance and replacement costs, and - pending other litigation. We sell gas to retail customers under tariffs approved by the MPSC. These tariffs measure the gas delivered to customers based on the volume (i.e. mcf) of gas delivered. However, we purchase gas for resale on a Btu basis. The Btu content of the gas available for purchase fluctuates and may result in CMS-31 CMS ENERGY CORPORATION 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 affect adversely 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. In September 2002, the FERC issued an order rejecting our filing to assess certain rates for non-physical gas title tracking services we offered. 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 that stated no refunds are at issue was in error. It directed us to file within 30 days a fair and equitable title-tracking fee and to make refunds to customers with interest based on the difference between the filed fee and the fee paid. We believe that with respect to the FERC jurisdictional transportation, we have not charged any customers title transfer fees, so no refunds will be required. We will make a filing within the 30 days and cannot predict the outcome of this proceeding. 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. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could change the remedial action costs for the sites. For additional details, see Note 3, Uncertainties, "Consumers' Gas Utility Contingencies - Gas Environmental 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 gas costs; however, the MPSC reviews these costs for prudency in an annual reconciliation proceeding. In January 2004, the MPSC staff and intervenors filed direct testimony in our 2002-2003 GCR case proposing GCR recovery disallowances. In 2003, we reserved $11 million for a settlement agreement associated with the 2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003 through February 2004, at Consumers' authorized rate of return, increased the cost of the settlement by $1 million. The interest was recorded as an expense in 2003. In February 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. For additional details, see Note 3, Uncertainties, "Consumers' Gas Utility Rate Matters - Gas Cost Recovery." 2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a $156 million annual increase in our gas delivery and transportation rates that included a 13.5 percent return on equity. In September 2003, we filed an update to our gas rate case that lowered the requested revenue increase from $156 million to $139 million and reduced the return on common equity from 13.5 percent to 12.75 percent. The MPSC authorized an interim gas rate increase of $19 million annually. The interim increase is under bond and subject to refund if the final rate relief is a lesser amount. The interim increase order includes a $34 million reduction in book depreciation expense and related income taxes effective only during the period of interim relief. The MPSC order allowed us to increase our rates beginning December 19, 2003. As part of the interim rate order, Consumers agreed to restrict dividend payments to its parent company, CMS Energy, to a maximum of $190 million annually during the period of the interim relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending that the MPSC not rely upon the projected test year data included in our filing and supported by the MPSC Staff and further recommended that the application be dismissed. In response to the Proposal for Decision, the parties have filed exceptions and replies to exceptions. The MPSC is not bound by the ALJ's recommendation and will CMS-32 CMS ENERGY CORPORATION review the exceptions and replies to exceptions prior to issuing an order on final rate relief. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. This case is not affected by the 2003 gas rate case interim increase order which reduced book depreciation expense and related income taxes only for the period that we receive the interim relief. The original filing was based on December 2000 plant balances and historical data. The December 2003 filing updates the gas depreciation case to include December 2002 plant balances. The proposed depreciation rates, if approved, will result in an annual increase of $12 million in depreciation expense based on December 2002 plant balances. The ALJ's Proposal for Decision is expected in May 2004. 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 Partnership estimates that the decision will result in a refund 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 2003 and expects to file an appeal contesting property taxes for 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund has not been recognized in first quarter 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 North America and the Middle East/North Africa. We will continue to sell designated assets and investments that are under-performing or are not synergistic with our other business units. We will continue to operate and manage our remaining portfolio of assets in a CMS-33 CMS ENERGY CORPORATION manner that maximizes their contribution to our earnings and that maintains our reputation for solid performance in the construction and operation of power plants. CMS ERM: CMS ERM has continued to streamline 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 continues to narrow its scope of existing operations. We plan to continue to sell international assets and businesses. Future operations will be mainly in Michigan. 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 Australia, - 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 substantially project expenses, - impact of any future rate cases, or FERC actions, or orders on regulated businesses, - impact of ratings downgrades on our liquidity, operating costs, and cost of capital, and - impact of restrictions by the Argentine government on natural gas exports to our GasAtacama plant. OTHER OUTLOOK 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 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. On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that have not CMS-34 CMS ENERGY CORPORATION 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. In addition, 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 $718 million at March 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.471 billion at March 31, 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 $120 million at March 31, 2004. Property, plant, and equipment serving as collateral for these obligations have a carrying value of $171 million. 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, and have not, restated 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 chart below details our involvement in these entities at March 31, 2004: CMS-35 CMS ENERGY CORPORATION
Name Investment Operating Total (Ownership Nature of the Involvement Balance Agreement with Generating Interest) Entity Country Date (In Millions) CMS Energy Capacity ------------ ------------------ ----------- ----------- -------------- -------------- ---------- Taweelah Power United Arab (40%) Generator Emirates 1999 $ 75 Yes 777 MW Generator - Saudi Jubail (25%) Under Construction Arabia 2001 $ - Yes 250 MW Generator - Shuweihat Under United Arab (20%) Construction Emirates 2001 $(30)(a) Yes 1,500 MW ---- ----- Total $ 45 2,527 MW ==== =====
(a) At March 31, 2004, we carried a negative investment in Shuweihat. The balance is comprised of our investment of $3 million reduced by our proportionate share of the negative fair value of derivative instruments of $33 million. We are required to record the negative investment due to our future commitment to make an equity investment in Shuweihat. Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $45 million, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $129 million, including a letter of credit relating to our required initial investment in Shuweihat of $70 million. We plan to contribute our initial investment when the project becomes commercially operational in 2004. In April 2004, we sold our investment in Loy Yang. In March 2004, we recorded an $81 million after-tax impairment charge. For additional information regarding the Loy Yang sale, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. EITF ISSUE NO. 02-03, RECOGNITION AND REPORTING OF GAINS AND LOSSES ON ENERGY TRADING CONTRACTS UNDER EITF ISSUES NO. 98-10 AND 00-17: At its October 25, 2002 meeting, the EITF reached a consensus to rescind EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. Energy trading contracts that do not meet the definition of a derivative must be accounted for as executory contracts. We recognized a loss for the cumulative effect of a change in accounting principle of $23 million, net of tax, during the three-month period ended March 31, 2003. ACCOUNTING STANDARDS NOT YET EFFECTIVE PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, 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 (Act), that was signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy 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. CMS-36 CMS ENERGY CORPORATION Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No. 106-1 and provides further guidance for accounting for the Act. Proposed FASB Staff Position, No. 106-b states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations (APBO) and postretirement benefit costs should reflect the effects of the Act. As of March 31, 2004, we have not determined whether our postretirement benefit plan is actuarially equivalent to Medicare Part D. Therefore, our measures of APBO and net periodic postretirement benefit cost do not reflect any amount associated with the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. If our prescription drug plan is determined to be actuarially equivalent to Medicare Part D, we estimate a decrease in OPEB expense of approximately $23 million for 2004 and a one-time reduction of our benefit obligation of approximately $150 million, to be amortized over future periods. This Proposed FASB Staff Position would be effective for the first interim or annual period beginning after June 15, 2004. STATEMENT OF POSITION, ACCOUNTING FOR CERTAIN COSTS AND ACTIVITIES RELATED TO PROPERTY, PLANT, AND EQUIPMENT: At its September 9, 2003 meeting, the Accounting Standards Executive Committee, of the American Institute of Certified Public Accountants voted to approve the Statement of Position, Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment. The Statement of Position was presented for FASB clearance in April 2004. The FASB elected not to clear this proposed Statement of Position. CMS-37 CMS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)
THREE MONTHS ENDED RESTATED MARCH 31 2004 2003 -------- ------- ------- In Millions, Except Per Share Amounts OPERATING REVENUE $ 1,754 $ 1,968 EARNINGS FROM EQUITY METHOD INVESTEES 19 47 OPERATING EXPENSES Fuel for electric generation 172 108 Purchased and interchange power 77 239 Purchased power - related parties - 136 Cost of gas sold 761 837 Other operating expenses 222 198 Maintenance 57 58 Depreciation, depletion and amortization 144 128 General taxes 74 69 Asset impairment charges 125 6 ------- ------- 1,632 1,779 ------- ------- OPERATING INCOME 141 236 OTHER INCOME (DEDUCTIONS) Accretion expense (6) (7) Gain (loss) on asset sales, net 2 (5) Interest and dividends 7 4 Other, net 7 7 ------- ------- 10 (1) ------- ------- FIXED CHARGES Interest on long-term debt 130 97 Interest on long-term debt - related parties 15 - Other interest 5 7 Capitalized interest (2) (2) Preferred dividends 4 - Preferred securities distributions - 18 ------- ------- 152 120 ------- ------- INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS (1) 115 INCOME TAX EXPENSE (BENEFIT) (3) 39 MINORITY INTERESTS 11 1 ------- ------- INCOME (LOSS) FROM CONTINUING OPERATIONS (9) 75 INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $1 TAX BENEFIT IN 2004 AND $18 TAX EXPENSE IN 2003 (2) 31 ------- ------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING (11) 106 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13 TAX BENEFIT IN 2003 : DERIVATIVES (NOTE 11) - (23) ASSET RETIREMENT OBLIGATIONS, SFAS NO. 143 (NOTE 10) - (1) ------- ------- - (24) NET INCOME (LOSS) $ (11) $ 82 ======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-38
THREE MONTHS ENDED RESTATED MARCH 31 2004 2003 -------- -------- -------- In Millions, Except Per Share Amounts CMS ENERGY NET INCOME (LOSS) Net Income (Loss) Available to Common Stock $ (11) $ 82 ======== ======== BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE Income (Loss) from Continuing Operations $ (0.06) $ 0.52 Income (Loss) from Discontinued Operations (0.01) 0.21 Loss from Changes in Accounting - (0.16) -------- -------- Net Income (Loss) Attributable to Common Stock $ (0.07) $ 0.57 ======== ======== DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE Income (Loss) from Continuing Operations $ (0.06) $ 0.47 Income (Loss) from Discontinued Operations (0.01) 0.19 Loss from Changes in Accounting - (0.14) -------- -------- Net Income (Loss) Attributable to Common Stock $ (0.07) $ 0.52 ======== ======== DIVIDENDS DECLARED PER COMMON SHARE $ - $ - -------- --------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-39 CMS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED RESTATED MARCH 31 2004 2003 -------- -------- -------- In Millions CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (11) $ 82 Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation, depletion and amortization (includes nuclear decommissioning of $1 and $2, respectively) 144 128 Loss (gain) on disposal of discontinued operations 1 (6) Asset impairments (Note 2) 125 6 Capital lease and debt discount amortization 8 2 Accretion expense 6 7 Bad debt expense 2 3 Undistributed earnings from related parties (6) (33) Loss (gain) on the sale of assets (2) 5 Cumulative effect of accounting changes - 24 Changes in other assets and liabilities: Increase in accounts receivable and accrued revenue (325) (136) Decrease in inventories 366 241 Decrease in accounts payable and accrued expenses (84) (40) Deferred income taxes and investment tax credit 70 27 Changes in other assets and liabilities (59) 105 -------- -------- Net cash provided by operating activities $ 235 $ 415 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excludes assets placed under capital lease) $ (113) $ (156) Cost to retire property (18) (17) Restricted cash (15) (4) Investment in Electric Restructuring Implementation Plan (2) (2) Investments in nuclear decommissioning trust funds (1) (2) Proceeds from nuclear decommissioning trust funds 20 6 Proceeds from sale of assets 5 97 Other investing 9 17 -------- -------- Net cash used in investing activities $ (115) $ (61) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from notes, bonds and other long-term debt $ - $ 326 Retirement of bonds and other long-term debt (263) (170) Decrease in notes payable - (201) Payment of capital lease obligations (3) (3) Other financing - (2) -------- -------- Net cash used in financing activities $ (266) $ (50) -------- -------- EFFECT OF EXCHANGE RATES ON CASH (9) 1 -------- -------- NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS $ (155) $ 305 CASH AND TEMPORARY CASH INVESTMENTS FROM EFFECT OF FIN 46R CONSOLIDATION 174 - CASH AND TEMPORARY CASH INVESTMENTS, BEGINNING OF PERIOD 532 351 -------- -------- CASH AND TEMPORARY CASH INVESTMENTS, END OF PERIOD $ 551 $ 656 ======== ========
CMS-40
THREE MONTHS ENDED RESTATED MARCH 31 2004 2003 -------- -------- -------- OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE: CASH TRANSACTIONS Interest paid (net of amounts capitalized) $ 155 $ 119 Income taxes paid (net of refunds) - - OPEB cash contribution 18 18 NON-CASH TRANSACTIONS Other assets placed under capital leases $ 1 $ 8 ======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-41 CMS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS
RESTATED MARCH 31 MARCH 31 2004 DECEMBER 31 2003 ASSETS (UNAUDITED) 2003 (UNAUDITED) ----------- ----------- ----------- In Millions PLANT AND PROPERTY (AT COST) Electric utility $ 7,698 $ 7,600 $ 7,356 Gas utility 2,891 2,875 2,787 Enterprises 3,408 895 684 Other 32 32 42 -------- -------- -------- 14,029 11,402 10,869 Less accumulated depreciation, depletion and amortization 5,942 4,846 4,737 -------- -------- -------- 8,087 6,556 6,132 Construction work-in-progress 405 388 496 -------- -------- -------- 8,492 6,944 6,628 -------- -------- -------- INVESTMENTS Enterprises Investments 710 724 754 Midland Cogeneration Venture Limited Partnership - 419 405 First Midland Limited Partnership - 224 259 Other 24 23 2 -------- -------- -------- 734 1,390 1,420 -------- -------- -------- CURRENT ASSETS Cash and temporary cash investments at cost, which approximates market 551 532 656 Restricted cash 216 201 43 Accounts receivable, notes receivable and accrued revenue, less allowances of $29, $29 and $14, respectively 734 367 392 Accounts receivable - Energy Resource Management, less allowances of $10, $11 and $9, respectively 29 36 305 Accounts receivable and notes receivable - related parties 69 73 179 Inventories at average cost Gas in underground storage 419 741 258 Materials and supplies 102 110 100 Generating plant fuel stock 41 41 26 Assets held for sale 66 24 305 Price risk management assets 88 102 95 Derivative instruments 118 14 - Prepayments and other 286 253 239 -------- -------- -------- 2,719 2,494 2,598 -------- -------- -------- NON-CURRENT ASSETS Regulatory Assets Securitized costs 637 648 678 Postretirement benefits 156 162 180 Abandoned Midland Project 10 10 11 Other 303 266 233 Assets held for sale 2 2 2,024 Price risk management assets 178 177 172 Nuclear decommissioning trust funds 566 575 529 Prepaid pension costs 383 388 - Goodwill 25 25 32 Notes receivable - related parties 231 242 148 Notes receivable 125 125 126 Other 556 390 422 -------- -------- -------- 3,172 3,010 4,555 -------- -------- -------- TOTAL ASSETS $ 15,117 $ 13,838 $ 15,201 ======== ======== ========
CMS-42
RESTATED MARCH 31 MARCH 31 2004 DECEMBER 31 2003 STOCKHOLDERS' INVESTMENT AND LIABILITIES (UNAUDITED) 2003 (UNAUDITED) ----------- ----------- ----------- In Millions CAPITALIZATION Common stockholders' equity Common stock, authorized 250.0 shares; outstanding 161.1 shares, 161.1 shares and 144.1 shares, respectively $ 2 $ 2 $ 1 Other paid-in capital 3,846 3,846 3,605 Other comprehensive loss (317) (419) (713) Retained deficit (1,855) (1,844) (1,718) -------- -------- -------- 1,676 1,585 1,175 Preferred stock of subsidiary 44 44 44 Preferred stock 261 261 - Company-obligated convertible Trust Preferred Securities of subsidiaries - - 393 Company-obligated mandatorily redeemable Trust Preferred Securities of Consumers' subsidiaries - - 490 Long-term debt 5,829 6,020 5,217 Long-term debt - related parties 684 684 - Non-current portion of capital leases 329 58 121 -------- -------- -------- 8,823 8,652 7,440 -------- -------- -------- MINORITY INTERESTS 754 73 41 -------- -------- -------- CURRENT LIABILITIES Current portion of long-term debt and capital leases 892 519 929 Notes payable - - 253 Accounts payable 257 296 359 Accounts payable - Energy Resource Management 19 21 131 Accounts payable - related parties - 40 55 Accrued interest 118 130 108 Accrued taxes 247 285 283 Liabilities held for sale 2 2 280 Price risk management liabilities 77 89 95 Current portion of purchase power contracts 19 27 26 Current portion of gas supply contract obligations 30 29 26 Deferred income taxes 40 27 23 Other 263 185 201 -------- -------- -------- 1,964 1,650 2,769 -------- -------- -------- NON-CURRENT LIABILITIES Postretirement benefits 264 265 732 Deferred income taxes 663 615 401 Deferred investment tax credit 84 85 89 Regulatory liabilities for income taxes, net 317 312 311 Regulatory liabilities for cost of removal 1,005 983 937 Other regulatory liabilities 175 172 152 Asset retirement obligation 401 359 365 Liabilities held for sale - - 1,266 Price risk management liabilities 174 175 165 Gas supply contract obligations 196 208 226 Power purchase agreement - MCV Partnership - - 21 Other 297 289 286 -------- -------- -------- 3,576 3,463 4,951 -------- -------- -------- COMMITMENTS AND CONTINGENCIES (Notes 1, 3 and 4) TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $ 15,117 $ 13,838 $ 15,201 ======== ======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-43 CMS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED)
THREE MONTHS ENDED RESTATED MARCH 31 2004 2003 -------- -------- -------- In Millions COMMON STOCK At beginning and end of period $ 2 $ 1 -------- -------- OTHER PAID-IN CAPITAL At beginning of period 3,846 3,605 Common stock repurchased - - Common stock reacquired - - Common stock issued - - -------- -------- At end of period 3,846 3,605 -------- -------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Minimum Pension Liability At beginning of period - (241) Unrealized gain (loss) on investments (a) - - -------- -------- At end of period - (241) -------- -------- Investments At beginning of period 8 2 Unrealized gain on investments (a) 1 - -------- -------- At end of period 9 2 -------- -------- Derivative Instruments At beginning of period (8) (31) Unrealized gain (loss) on derivative instruments (a) (3) 7 Reclassification adjustments included in net income (loss) (a) (2) (5) -------- -------- At end of period (13) (29) -------- -------- Foreign Currency Translation At beginning of period (419) (458) Change in foreign currency translation (a) 106 13 -------- -------- At end of period (313) (445) -------- -------- At end of period (317) (713) -------- -------- RETAINED DEFICIT At beginning of period (1,844) (1,800) Net income (loss) (a) (11) 82 Common stock dividends declared - - -------- -------- At end of period (1,855) (1,718) -------- -------- TOTAL COMMON STOCKHOLDERS' EQUITY $ 1,676 $ 1,175 ======== ======== (a) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS): Minimum Pension Liability Minimum pension liability adjustments, net of tax of $- and $-, respectively $ - $ - Investments Unrealized gain on investments, net of tax of $- and $-, respectively 1 - Derivative Instruments Unrealized gain (loss) on derivative instruments, net of tax of $5 and $5, respectively (3) 7 Reclassification adjustments included in net income (loss), net of tax benefit of $(1) and $(3), respectively (2) (5) Foreign currency translation, net 106 13 Net income (loss) (11) 82 -------- -------- Total Other Comprehensive Income $ 91 $ 97 ======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CMS-44 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 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. 1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES CORPORATE STRUCTURE: CMS Energy is the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through subsidiaries, is engaged in domestic and international diversified energy businesses including independent power production, natural gas transmission, storage and processing, and energy services. PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the accounts of CMS Energy, Consumers and 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, which are ownership, contractual, or other economic interests. As of and for the quarter ended March 31, 2004, we determined that the MCV Partnership and the FMLP should be consolidated 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. Management is required to make estimates using assumptions that 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. CMS-45 CMS Energy Corporation 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 March 31, 2004, our restricted cash on hand was $216 million. Restricted cash primarily includes cash collateral for letters of credit to satisfy certain debt agreements and cash dedicated for repayment of Securitization bonds. It is classified as a current asset as the related letters of credit mature within one year and the payments on the related Securitization 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 in accordance with SFAS No. 115. Debt and equity securities can be classified into one of three categories: held-to-maturity, trading, or available-for-sale. 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 and are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses from changes in the fair value of our nuclear decommissioning investments are reported as regulatory liabilities. The fair value of these investments is determined from quoted market prices. Our debt securities are classified as held-to-maturity securities and are reported at cost. 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 in the 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 CMS-46 CMS Energy Corporation in determining net income. For the three months ended March 31, 2004, the change in the foreign currency translation adjustment increased equity by $106 million and for the three months ended March 31, 2003, the change in the foreign currency translation adjustment increased equity by $13 million. 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 March 31, 2004, we have recorded a liability to the DOE for $139 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." 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 and 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 $5 million for the three months ended March 31, 2004 and $97 million for the three months ended March 31, 2003. CMS-47 CMS Energy Corporation DISCONTINUED OPERATIONS We have discontinued the following operations:
In Millions ------------------------------------------------------------------------------------- Pretax After-tax Business/Project Discontinued Gain(Loss) Gain(Loss) Status ------------------ ------------- ---------- ---------- ------------------ CMS Viron June 2002 (14) (9) Sold June 2003 Panhandle December 2002 (39) (44) Sold June 2003 CMS Field Services December 2002 (5) (1) Sold July 2003 Marysville June 2003 2 1 Sold November 2003 Parmelia (a) December 2003 -- -- Held for sale
(a) We expect the sale of Parmelia to occur in 2004. In December 2003, we reduced the carrying amount of our Parmelia business to reflect fair value. The $26 million after-tax loss was reported in discontinued operations in December 2003. At March 31, 2004, "Assets held for sale" includes Parmelia, our investment in Loy Yang, and our investment in the American Gas Index fund. Although Loy Yang and the American Gas Index fund are considered held for sale, they did not meet the criteria for discontinued operations. At March 31, 2003, "Assets held for sale" includes Panhandle, CMS Viron, CMS Field Services, Marysville, and Parmelia. The major classes of assets and liabilities held for sale are as follows:
In Millions -------------------------------------------------------------------------------- Restated March 31 December 31 March 31 2004 2003 2003 -------- ----------- -------- Assets Cash $ 8 $ 7 $ 65 Accounts receivable 14 2 160 Property, plant and equipment - net 2 2 1,833 Goodwill - - 117 Other 44 15 154 -------- ----------- -------- Total assets held for sale $ 68 $ 26 $ 2,329 ======== =========== ======== Liabilities Accounts payable $ 2 $ 2 $ 97 Long-term debt - - 1,147 Minority interest - - 44 Other - - 258 -------- ----------- -------- Total liabilities held for sale $ 2 $ 2 $ 1,546 ======== =========== ========
CMS-48 CMS Energy Corporation The following amounts are reflected in the Consolidated Statements of Income (Loss) from discontinued operations:
In Millions ------------------------------------------------------------------------------- Restated Three months ended March 31 2004 2003 --------------------------------------------------------- ------ -------- Revenues $ 5 $ 246 ====== ======== Discontinued operations: Pretax income gain (loss) from discontinued operations $ (1) $ 40 Income tax expense - 15 ------ -------- Income (loss) from discontinued operations (1) 25 Pretax gain (loss) on disposal of discontinued operations (2) 9 Income tax expense (benefit) (1) 3 ------ -------- Gain (loss) on disposal of discontinued operations (1) 6 ------ -------- Income (loss) from discontinued operations $ (2) $ 31 ====== ========
The income (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 three months ended March 31, 2004 and $11 million for the three months ended March 31, 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 times 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 three months ended March 31, 2004, 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 --------- ------------------------- ------ --------- February Bluewater Pipeline (a) $ 1 $ 1 Various Other 1 1 ------ --------- Total gain on asset sales $ 2 $ 2 ====== =========
(a) Bluewater Pipeline is a 24.9 mile pipeline that extends from Marysville, Michigan to Armada, Michigan. For the three months ended March 31, 2003, we sold the following assets that did not meet the definition CMS-49 CMS Energy Corporation of, and therefore were not reported as, discontinued operations:
In Millions ------------------------------------------------------------- Pretax After-tax Date sold Business/Project Gain(Loss) Gain(Loss) --------- ---------------- ---------- ---------- January CMS MST Wholesale Gas $ (6) $ (4) March CMS MST Wholesale Power 2 1 Various Other (1) - ---- ---- Total loss on asset sales $ (5) $ (3) ==== ====
In April 2004, we and our partners sold the 2,000-megawatt 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 gross proceeds was about $54 million and is subject to closing adjustments and transaction costs. In anticipation of the sale, we recorded an impairment in the first quarter as reflected below. 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. 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 ----------------------------------------------------------------- Pretax After-tax Pretax After-tax Three months ended March 31 2004 2004 2003 2003 --------------------------- ------ --------- ------ --------- Asset impairments: Enterprises (a) $ - $ - $ 6 $ 4 Loy Yang (b) 125 81 - - ------ ---- --- --- Total asset impairments $ 125 $ 81 $ 6 $ 4 ====== ==== === ===
(a) In the first quarter of 2003, an impairment was recorded to reflect the fair value of two generators. (b) 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. RESTRUCTURING AND OTHER COSTS In June 2002, we announced a series of initiatives to reduce our annual operating costs by an estimated $50 million. As such, we: CMS-50 CMS Energy Corporation - relocated CMS Energy's corporate headquarters from Dearborn, Michigan to a new combined CMS Energy and Consumers headquarters in Jackson, Michigan in July 2003, - implemented changes to our 401(k) savings program, - implemented changes to our health care plan, and - completed the termination of numerous employees, including five officers. The following tables shows the amount charged to expense for restructuring costs, the payments made, and the unpaid balance of accrued costs for the three months ended March 31, 2004 and March 31, 2003.
In Millions ----------------------------------------------------------------------------- March 31, 2004 --------------------------------- Involuntary Lease Termination Termination Total ----------- ----------- ----- Beginning accrual balance, January 1, 2004 $ 3 $ 6 $ 9 Expense - - - Payments (1) (1) (2) ---- ---- ---- Ending accrual balance at March 31, 2004 $ 2 $ 5 $ 7 ==== ==== ====
In Millions ----------------------------------------------------------------------------- March 31, 2003 --------------------------------- Involuntary Lease Termination Termination Total ----------- ----------- ----- Beginning accrual balance, January 1, 2003 $ 12 $ 8 $ 20 Expense 1 - 1 Payments (5) - (5) ---- ---- ----- Ending accrual balance at March 31, 2003 $ 8 $ 8 $ 16 ===== ==== =====
3: UNCERTAINTIES Several business trends or uncertainties may affect our financial results. 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 CMS-51 CMS ENERGY CORPORATION 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. Based on his decision with respect to the motion to amend, the judge dismissed certain of plaintiffs' claims without prejudice and denied without prejudice the motions to dismiss other claims. The judge will permit CMS Energy and the other defendants to renew the motions to dismiss at or shortly after the hearing on the motion to amend. CMS Energy, Consumers, and their affiliates 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 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 June 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 CMS-52 CMS ENERGY CORPORATION 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 are now required to file answers to the amended complaint on or before May 14, 2004. 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.) 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. Some of the defendants in the MDL matter who are also defendants in the Texas-Ohio case are trying to have the Texas-Ohio case transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case has agreed to extend the time for all defendants to answer or otherwise respond until after the MDL panel decides whether to take the case. 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 and are seeking to have it transferred to the MDL proceeding in Nevada. CMS Energy and the other CMS defendants will defend themselves vigorously, but cannot predict the outcome of these matters. CMS-53 CMS ENERGY CORPORATION CONSUMERS' UNCERTAINTIES Several business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we 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 expenses 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 being followed by the MPSC, - recovery of electric restructuring implementation costs, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer, instead of an electric transmission owner-operator. Regulatory - effects of potential performance standards payments, - successful implementation of initiatives to reduce exposure to purchased power price increases, - recovery of nuclear decommissioning costs, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, - inadequate regulatory response to applications for requested rate increases, and - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers. Other - pending litigation regarding PURPA qualifying facilities, and - pending other 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: In 1998, the EPA issued regulations requiring the state of Michigan to further limit nitrogen oxide emissions at our coal-fired electric plants. The Michigan Department of Environmental Quality finalized its rules to comply with the EPA regulations in December 2002. The EPA's conditional approval of the Michigan rules was published in April 2004. The Michigan Department of Environmental Quality is currently correcting deficiencies in its rules that were identified by the EPA. If the Department of Environmental Quality fails to submit satisfactory revisions to the EPA by the end of May 2004, the EPA's conditional approval will automatically revert to a disapproval and similar federal regulations will take effect. The EPA and the state regulations require us to make significant capital expenditures estimated to be CMS-54 CMS ENERGY CORPORATION $771 million. As of March 31, 2004, we have incurred $469 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 2009. These expenditures include installing catalytic reduction technology on 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 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. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost of these credits is estimated to average $8 million per year and is accounted for as inventory. The credit inventory is expensed as the coal-fired electric plants generate electricity. The price for nitrogen oxide emissions credits is volatile and could change substantially. The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which requires 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 required to reduce nitrogen oxide emissions 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, through the installation of flue gas desulfurization scrubbers and selective catalytic reduction units. 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. Several bills have been introduced in the United States Congress that would require carbon dioxide emissions reduction. We cannot predict whether any federal mandatory carbon dioxide emissions reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that emissions reduction rules comes into legal 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. 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. CMS-55 CMS Energy Corporation 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 March 31, 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 PSCR plan) 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. 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. We cannot predict the outcome of this matter. CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS ELECTRIC RESTRUCTURING LEGISLATION: 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 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 an annual return of and on capital expenditures in excess of depreciation levels incurred during and before the rate freeze-cap period, - 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, CMS-56 CMS Energy Corporation - 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 jointly expand 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 in order to comply with the Customer Choice Act; for additional details regarding the sale of the transmission facility, see "Transmission Sale" within this section. 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 competitor suppliers. As of April 2004, alternative electric suppliers are providing 823 MW of load. This amount represents 10 percent of the total distribution load and an increase of 50 percent compared to April 2003. ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric restructuring proceedings. They are: - Securitization, - Stranded Costs, - implementation costs, and - transmission. 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. We will recover the repayment of principal, interest, and other expenses relating to the bond issuance CMS-57 CMS Energy Corporation 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 2003 true up modified the total Securitization and related tax charges from 1.746 mills per kWh to 1.718 mills per kWh. There will be no impact on customer bills from Securitization for most of our electric customers until the Customer Choice Act cap period expires, and an electric rate case is processed. Securitization charge collections, $13 million for the three months ended March 31, 2004, and $13 million for the three months ended March 31, 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. This amount relates to Clean Air Act expenditures and associated return on those expenditures through December 31, 2002; ROA implementation costs, and previously authorized return on those expenditures through December 31, 2000; and other up front qualified costs related to issuance of the Securitization bonds. In July 2003, we filed for rehearing and clarification on a number of features in the financing order. In December 2003, the MPSC issued its order on rehearing, which rejected our requests for clarification and modification to the dividend payment restriction, failed to rule directly on the accounting clarifications requested, and remanded the proceeding to the ALJ for additional proceedings to address rate design. The ALJ completed hearings in March 2004 and the MPSC decision is not anticipated before May 2004, but could be later. The financing order will become effective after our acceptance of a favorable MPSC order. Bonds will not be issued until resolution of any appeals. Stranded Costs: The Customer Choice Act allows electric utilities to recover their net Stranded Costs, without defining the term. The Act directs the MPSC to establish a method of calculating net Stranded Costs and of conducting related true-up adjustments. 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 transition charge. However, the MPSC has not yet allowed such a transition charge. As a result, we have not recorded regulatory assets to recognize the future recovery of such costs. In 2002 and 2001, the MPSC issued orders finding that we experienced zero net Stranded Costs from 1999 to 2001. The MPSC also declined to resolve numerous issues regarding the net Stranded Cost methodology in a way that would allow a reliable prediction of the level of Stranded Costs for future years. We are currently in the process of appealing these orders with the Michigan Court of Appeals and the Michigan Supreme Court. In March 2003, we filed an application with the MPSC seeking approval of net Stranded Costs incurred CMS-58 CMS Energy Corporation in 2002, and for approval of a net Stranded Cost recovery charge. Our net Stranded Costs incurred in 2002, including the cost of money, are estimated to be $47 million with the issuance of Securitization bonds that include Clean Air Act investments, or $104 million without the issuance of Securitization bonds that include Clean Air Act investments. The MPSC scheduled hearings for our 2002 Stranded Cost application to take place during the second quarter of 2004. Once a final financing order on Securitization is reached, we will know the amount of our request for net Stranded Cost recovery for 2002. In February 2004, the MPSC issued an order on Detroit Edison's request for rate relief for costs associated with customers leaving under electric customer choice. The MPSC order allows Detroit Edison to charge a transition surcharge to ROA customers and eliminates Securitization charge offsets. In April 2004, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2003, including the cost of money, in the amount of $106 million with the issuance of Securitization bonds that include Clean Air Act investments, or $165 million without the issuance of Securitization bonds that include Clean Air Act investments. Similar to the request that was granted by the MPSC for Detroit Edison, we also requested interim relief for 2002 and 2003 net Stranded Costs. We cannot predict whether the Stranded Cost recovery method adopted by the MPSC will be applied in a manner that will fully offset any associated margin loss from ROA. Implementation Costs: The Customer Choice Act allows electric utilities to recover their implementation costs. The following table outlines the applications filed by us with the MPSC and the status of recovery for these costs.
In Millions -------------------------------------------------------------------------------- Year Filed Year Incurred Requested Pending Allowed Disallowed -------------------------------------------------------------------------------- 1999 1997 & 1998 $20 $ - $15 $5 2000 1999 30 - 25 5 2001 2000 25 - 20 5 2002 2001 8 - 8 - 2003 & 2004 (a) 2002 7 7 Pending Pending 2004 2003 1 1 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. The MPSC disallowed certain costs, determining that these amounts did not represent costs incremental to costs already reflected in electric rates. In the order received for the year 2001, the MPSC also reserved the right to reevaluate the implementation costs depending upon the progress and success of the ROA program, and ruled that due to the rate freeze imposed by the Customer Choice Act, it was premature to establish a cost recovery method for the allowable implementation costs. In addition to the amounts shown above, we incurred and deferred as a regulatory asset, as of March 31, 2004, $23 million for the cost of money associated with total implementation costs. We believe the implementation costs and associated cost of money are fully recoverable in accordance with the Customer Choice Act. We expect cash recovery from customers to begin after rate cap periods expire. The rate cap expired for large commercial and industrial customers on December 31, 2003. In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision finding that the recovery of 1999 implementation costs is conditional and subject to later disallowance is unlawful. The case was remanded to the MPSC. The MPSC issued an order regarding the remanded proceeding that directed us to choose whether we prefer to recover our approved implementation costs through Securitization pursuant to the MPSC's final order in the Securitization proceeding or whether we would prefer to have recovery controlled by the remand proceeding. If the latter option was chosen, the MPSC indicated that it intended to authorize recovery of such implementation costs through the use of surcharges on all customer classes that coincide with the expiration of the Customer Choice Act rate caps. We chose recovery of the approved implementation costs through the use of surcharges and withdrew our request for approved implementation costs recovery from our Securitization proposal. The implementation costs withdrawn from the Securitization case were incurred for the years 1998 through 2000. In the filing we made electing recovery through separate surcharges, we requested approval of surcharges that would allow recovery of implementation costs incurred for the years 1998 through 2001. We requested that the Court of Appeals issue similar remand orders with respect to appeals of the MPSC orders addressing 2000 and 2001 implementation costs. We cannot predict the amounts the MPSC will approve as recoverable costs. CMS-59 CMS Energy Corporation Also, we are pursuing authorization at the FERC for the MISO to reimburse us for $8 million in certain electric utility restructuring implementation costs related to our former participation in the development of the Alliance RTO, a portion of which has been expensed. The FERC issued an order denying the MISO's request for authorization to reimburse us and we are in the process of appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. We also requested that the MISO seek authorization to reimburse METC for these development costs. The MISO filed this request but the FERC denied it. While we appeal the FERC's orders, we are also pursuing other potential means of recovery, such as recovery of Alliance RTO development costs at the MPSC. We cannot predict the outcome of the appeal process or the ultimate amount, if any, we will collect for Alliance RTO development costs. Security Costs: The Customer Choice Act allows for recovery of new and enhanced security costs, as a result of federal and state regulatory security requirements. All retail customers, except customers of alternative electric suppliers, would pay these charges. In April 2004, we filed a security cost recovery case with the MPSC for $25 million of cost that regulatory treatment has not yet been granted through other means. The costs are for enhanced security and insurance because of federal and state regulatory security requirements imposed after the September 11, 2001 terrorist attacks. We cannot predict how the MPSC will rule on our requests for the recoverability of security costs. 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 for $290 million to MTH, a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc. The pretax gain was $31 million ($26 million, net of tax). We are currently in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. We cannot predict whether remaining open items will affect materially the recorded gain on the sale. As a result of the sale, after-tax earnings have decreased due to a loss of revenue from wholesale and ROA customers who will buy services directly from MTH. METC has completed the capital program to expand the transmission system's capability to import electricity into Michigan, as required by the Customer Choice Act. We will continue to maintain the system until May 1, 2007 under a contract with METC. Under an agreement with MTH, our transmission rates are fixed by contract at current levels through December 31, 2005, and are subject to the FERC ratemaking thereafter. However, we are subject to certain additional MISO surcharges, which we estimate to be $15 million in 2004. CONSUMERS' ELECTRIC UTILITY RATE MATTERS PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. They relate to restoration after an outage, safety, and customer relations. During 2002 and 2003, we monitored and reported to the MPSC our performance relative to the performance standards. Year-end results for both 2002 and 2003 resulted in compliance with the acceptable level of performance as established by the approved standards. Financial incentives and penalties are contained within the performance standards. An incentive is possible if all of the established performance standards have been exceeded for a calendar year. However, the performance standards do not contain an approved incentive mechanism; therefore, the value of such incentive cannot be determined at this point. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. 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 incentive or penalties, if any, on us, nor can we predict the outcome of the appeal. CMS-60 CMS Energy Corporation 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 call options and 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 of March 31, 2004, we 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 $19 million for unexpired capacity and energy contracts. On March 31, 2004, we filed a summer assessment for meeting 2004 peak load demand as required by the MPSC, stating that our summer 2004 reserve margin target is 11 percent or supply resources equal to 111 percent of projected summer peak load. Presently, we have a reserve margin of 12 percent, or supply resources equal to 112 percent of projected summer peak load for summer 2004. Of the 112 percent, approximately 103 percent is from owned electric generating plants and long-term contracts, and approximately 9 percent is from short-term contracts. This reserve margin met our summer 2004 reserve margin target. The total premium costs of electricity call options and capacity and energy contracts for 2004 is expected to be approximately $9 million, as of April 30, 2004. As a result of meeting the transmission capability expansion requirements and the market power test, as discussed in 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. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $30 million in 2004. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. The revenues received from the PSCR charge are also subject to subsequent reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of this filing. 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. Our consolidated retained earnings include undistributed earnings from the MCV Partnership, which at March 31, 2004 are $248 million and at March 31, 2003 are $233 million. The MCV Partnership and the FMLP are variable interest entities and Consumers was determined to be the primary beneficiary. Therefore, we have consolidated the MCV Partnership and the FMLP into our consolidated financial statements for the first time as of and for the quarter ended March 31, 2004. For additional details, see Note 11, Implementation of New Accounting Standards. CMS-61 CMS Energy Corporation 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 MCV Partnership that capped 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. The remaining liability associated with the loss totaled $19 million at March 31, 2004 and $47 million at March 31, 2003. We expect the PPA liability to be depleted in late 2004. 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. We will expense all cash underrecoveries directly to income once the PPA liability is depleted. 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, we returned to dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in order to maximize recovery 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's Partnership's financial performance and investment in the MCV Partnership is and will be harmed. CMS-62 CMS Energy Corporation 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, while 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. In February 2004, we filed a resource conservation plan 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 resource conservation plan will reduce the MCV Facility's annual natural gas consumption by an estimated 30 to 40 billion cubic feet. 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 April 2004, the presiding ALJ at the MPSC held a pre-hearing conference regarding the resource conservation plan. The ALJ denied our request to establish a schedule that would have allowed consideration of the plan on an interim basis and established a review schedule that calls for a Proposal for Decision in September 2004 after which point the MPSC would consider the plan. We cannot predict if or when the MPSC will approve our resource conservation plan. 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 22 years and the MPSC's decision in 2007 or beyond on limiting our recovery of capacity and fixed energy payments. Natural gas prices have been volatile historically. Presently, there is no consensus in the marketplace on the price or range of prices of natural gas in the short term or beyond the next five years. Even with an approved resource conservation plan, 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 of approximately $35 million in taxes plus $9 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan CMS-63 CMS Energy Corporation Court of Appeals by the City of Midland and the MCV Partnership has file 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 2003 and expects to file an appeal contesting property taxes for 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund has not been recognized in first quarter 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. 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 levels of funds provided by the trusts are 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 in "Nuclear Matters" within this section. 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 approximately $25 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, again 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 need to be increased to approximately $25 million annually, beginning January 1, 2006, and continue through 2011, our current license expiration date. We plan to file an application with the MPSC seeking approval to increase the surcharge for recovery of decommissioning costs related to Palisades, beginning in 2006. We cannot predict how the MPSC will rule on our 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 CMS-64 CMS Energy Corporation 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 Michigan Department of Environmental Quality continue to find all decommissioning activities at Big Rock are being performed in accordance with applicable regulations including license requirements. Palisades: In March 2004, the NRC completed its end-of-cycle plant performance assessment of Palisades. The assessment for Palisades covered the period from January 1, 2003 through December 31, 2003. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. As of March 2004, all inspection findings were classified as having very low safety significance and all performance indicators indicated performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through September 2005. The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of March 31, 2004, we have loaded 18 dry casks with spent nuclear fuel and are scheduled to load additional dry casks this summer in order to continue operation. 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. A number of utilities have initiated litigation in the United States Court of Claims; we filed our complaint in December 2002. If our litigation against the DOE is successful, we anticipate future recoveries from the DOE. The recoveries will be used 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. The next step will be for the DOE to submit 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. CMS-65 CMS Energy Corporation 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. 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 2005, and total an estimated $182 million. Our coal transportation contracts expire through 2007, and total an estimated $132 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 unknown at this time, we believe that it will be within the historic 60 to 90 percent range. Power Supply, Capacity, and Transmission: As of March 31, 2004, we had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2004 and 2005 totaling $7 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 $3.064 billion, undiscounted. This amount may vary depending upon plant availability and fuel costs. If a plant was not available to deliver electricity to us, then we would not be obligated to make the capacity payment until the plant could deliver. CMS-66 CMS Energy Corporation CONSUMERS' GAS UTILITY CONTINGENCIES GAS ENVIRONMENTAL MATTERS: We expect to have 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 March 31, 2004, we have recorded a liability of $42 million, net of $39 million of expenditures incurred to date, and a regulatory asset of $67 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 gas costs; however, the MPSC reviews these costs for prudency in an annual reconciliation proceeding. 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 using a roll-in methodology. The roll-in methodology incorporates the GCR under-recovery 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 2003 GCR case. Their positions were that not all of our gas purchasing decisions were prudent during April 2002 through March 2003 and they proposed disallowances. In 2003, we reserved $11 million for a settlement agreement associated with the 2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003 through February 2004, at Consumers' authorized rate of return, increased the cost of the settlement by $1 million. The interest was recorded as an expense in 2003. In February 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. We plan to file a 2003-2004 GCR reconciliation in June 2004. CMS-67 CMS Energy Corporation In March 2004, the MPSC approved a temporary settlement authorizing us to bill a maximum allowable GCR factor with two quarterly adjustments. The current GCR ceiling factor is $5.94 per mcf, and this is the amount included for May 2004 bills. We are continuing to work with the parties in the case to obtain a final settlement in the 2004-2005 GCR plan case. 2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a $156 million annual increase in our gas delivery and transportation rates that included a 13.5 percent return on equity. In September 2003, we filed an update to our gas rate case that lowered the requested revenue increase from $156 million to $139 million and reduced the return on common equity from 13.5 percent to 12.75 percent. The MPSC authorized an interim gas rate increase of $19 million annually. The interim increase is under bond and subject to refund if the final rate relief is a lesser amount. The interim increase order includes a $34 million reduction in book depreciation expense and related income taxes effective only during the period that we receive the interim relief. The MPSC order allowed us to increase our rates beginning December 19, 2003. As part of the interim order, Consumers agreed to restrict dividend payments to its parent company, CMS Energy, to a maximum of $190 million annually during the period of the interim relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending that the MPSC not rely upon the projected test year data included in our filing and supported by the MPSC Staff and further recommended that the application be dismissed. In response to the Proposal for Decision the parties have filed exceptions and replies to exceptions. The MPSC is not bound by the ALJ's recommendation and will review the exceptions and replies to exceptions prior to issuing an order on final rate relief. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. This case is not affected by the 2003 gas rate case interim increase order, which reduced book depreciation expense and related income taxes only for the period that we receive the interim relief. The original filing was based on December 2000 plant balances and historical data. The December 2003 filing updates the gas depreciation case to include December 2002 plant balances. The proposed depreciation rates, if approved, will result in an annual increase of $12 million in depreciation expense based on December 2002 plant balances. The ALJ's Proposal for Decision is expected in May 2004. OTHER UNCERTAINTIES 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 parties are now awaiting transfer of the file from Wayne County to CMS-68 CMS Energy Corporation Jackson County. 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. CMS GENERATION-OXFORD TIRE RECYCLING: In an administrative order, the California Regional Water Control Board of the state of California named CMS Generation as a potentially responsible party for the clean up of the waste from the fire that occurred in September 1999 at the Filbin Tire Pile, which the State claims was owned by Oxford Tire Recycling of North Carolina, Inc. CMS Generation reached a settlement with the state, which the court approved, pursuant to which CMS Generation paid the state $5.5 million, $1.6 million of which it had paid the state prior to the settlement. CMS Generation continues to negotiate to have the insurance company pay a portion of the settlement amount, as well as a portion of its attorney fees. At the request of the DOJ in San Francisco, CMS Energy and other parties contacted by the DOJ in San Francisco entered into separate Tolling Agreements with the DOJ in San Francisco in September 2002. The Tolling Agreement stops the running of any statute of limitations during the ninety-day period between September 13, 2002 and (through several extensions of the tolling period) March 30, 2004, to facilitate settlement discussions between all the parties in connection with federal claims arising from the fire at the Filbin Tire Pile. On September 23, 2002, CMS Energy received a written demand from the U.S. Coast Guard for reimbursement of approximately $3.5 million in costs incurred by the U.S. Coast Guard in fighting the fire. It is CMS Energy's understanding that these costs, together with any accrued interest, are the sole basis of any federal claims. CMS Energy has entered into a consent judgment with the U.S. Coast Guard to settle this matter for $475,000 that is awaiting final DOJ and court approval. 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 seeks 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 amended complaint was filed on behalf of six named plaintiffs, all alleged to be adjacent or nearby residents or property owners. The damages alleged are injury to persons and property of the landowners. Certification of a class of "potentially thousands" who have been similarly affected is requested. DIG intends to defend this action aggressively but cannot predict the outcome of this matter. 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 CMS-69 CMS Energy Corporation 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. CMS Energy has appealed this judgment. 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 power 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 natural gas to Argentina for six months. This Agreement should eliminate or greatly reduce the current domestic gas supply shortage in Argentina. Bolivia has voiced its opposition to any of its gas supply being exported to Chile. However, the government of Argentina has announced a settlement with Argentine producers that should help solve Argentina's long-term gas shortage problems. Currently, management of GasAtacama is working with government officials of both Chile and Argentina, as well as meeting with its electricity customers and gas producers, to attempt to mitigate the impact of this situation. At this point, it is not possible to predict the outcome of these events and their effect on the earnings of GasAtacama. 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 previously used the U.S. dollar as the functional currency for these investments. As a result, on April 30, 2002, we translated the assets and liabilities of our Argentine entities into U.S. dollars, in accordance with SFAS No. 52, using an exchange rate of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign Currency Translation component of Common Stockholders' Equity of approximately $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, political risk insurance, and the eventual sale of these assets. At March 31, 2004, the net foreign currency loss due to the unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency Translation component of Common Stockholders' Equity using an exchange rate of 2.86 pesos per U.S. dollar was $262 million. This amount also reflects the effect of recording U.S. income taxes with respect to temporary differences between the book and tax basis of foreign investments, including the foreign currency translation associated with our Argentine investments, that were determined to no longer be essentially permanent in duration. 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 CMS-70 CMS Energy Corporation 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. However, 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 OPIC. Enterprises is party to a Sponsor Support Agreement pursuant to which Enterprises has guaranteed CMS Ensenada's debt service payments to OPIC up to an amount which is in dispute, but which Enterprises estimated to be approximately $11 million at March 31, 2004. Following a payment made to OPIC in April 2004, Enterprises now believes this amount to be approximately $9 million. An interim arrangement, which provided CMS Ensenada with payments under the PPA 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 PPA 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 PPA is unconstitutional, or, alternatively, that the arbitral panel reestablish the economic equilibrium of the PPA, 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. 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 in this Note, Consumers and certain other subsidiaries of CMS Energy are parties to certain lawsuits and administrative proceedings before various courts and CMS-71 CMS Energy Corporation 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 in this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or results of operations. 4: FINANCINGS AND CAPITALIZATION Long-term debt is summarized as follows:
In Millions ------------------------------------------------------------------------------- March 31 December 31 2004 2003 ------------------------------------------------------------------------------- CMS ENERGY CORPORATION Senior notes $ 2,063 $ 2,063 General term notes 246 496 Extendible tenor rate adjusted securities and other 187 187 ------- ------- Total - CMS Energy Corporation 2,496 2,746 ------- ------- CONSUMERS ENERGY COMPANY First mortgage bonds 1,483 1,483 Senior notes 1,254 1,254 Bank debt and other 469 469 Securitization bonds 419 426 FMLP debt 411 - ------- ------- Total - Consumers Energy Company 4,036 3,632 ------- ------- OTHER SUBSIDIARIES 184 191 ------- ------- Total principal amount outstanding 6,716 6,569 Current amounts (849) (509) Net unamortized discount (38) (40) ------------------------------------------------------------------------------- Total consolidated long-term debt $ 5,829 $ 6,020 ===============================================================================
FMLP DEBT: We consolidated the FMLP due to the adoption of Revised FASB Interpretation No. 46. At March 31, 2004, long-term debt of the FMLP, which is consolidated into our financial statements for the first time, consists of:
In Millions ------------------------------------------------------------------------------ Maturity 2004 ------------------------------------------------------------------------------ 11.75% subordinated secured notes 2005 $185 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 $411 ==============================================================================
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. DEBT MATURITIES: At March 31, 2004, the aggregate annual maturities for long-term debt for the nine months ending December 31, 2004 and the next four years are: CMS-72 CMS Energy Corporation
In Millions -------------------------------------------------------------------------------- Payments Due -------------------------------------------------------------------------------- 2004 2005 2006 2007 2008 -------------------------------------------------------------------------------- Long-term debt $ 362 $ 785 $ 546 $ 545 $ 1,050 ================================================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: At March 31, 2004, Consumers had remaining FERC authorization to issue or guarantee up to $500 million of short-term securities and up to $700 million of short-term first mortgage bonds as collateral for such short-term securities. At March 31, 2004, Consumers had remaining FERC authorization to issue up to $740 million of long-term securities for refinancing or refunding purposes, $560 million of long-term securities for general corporate purposes, and $2 billion of long-term first mortgage bonds to be issued solely as collateral for other long-term securities. The authorizations expire on June 30, 2004 and Consumers plans to file a renewal application in early May 2004. SHORT-TERM FINANCINGS: At March 31, 2004, CMS Energy has a $190 million revolving credit facility with banks. All of the $190 million is available for general corporate purposes. Consumers has a $400 million revolving credit facility with banks of which $376 million is available for general corporate purposes, working capital, and letters of credit. The MCV Partnership has 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 LEASE OBLIGATIONS: 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. The MCV Partnership classifies this transaction as a capital lease. As of March 31, 2004, capital lease obligations total $ 372 million, of which $307 million represents the third-party portion of the MCV Facility capital lease. 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 no receivables at March 31, 2004 and we sold $325 million at March 31, 2003. The Consolidated Balance Sheets exclude these amounts from accounts receivable. We continue to service the receivables sold. 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 received from and paid to us under our accounts receivable sales program are shown below:
In Millions -------------------------------------------------------------------------------- Three Months Ended March 31 2004 2003 -------------------------------------------------------------------------------- Proceeds from sales (remittance of collections) under the program $ (297) $ - Collections reinvested under the program $ 1,549 $1,375 ================================================================================
DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at March 31, 2004, Consumers had $397 million of unrestricted retained earnings available to pay common dividends. CMS-73 CMS Energy Corporation However, covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. Consumers is also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. As of March 31, 2004, CMS Energy has received $78 million of common stock dividends from Consumers. Our $190 million revolving credit facility with banks, which expires in November 2004, contains provisions that prohibit us from paying dividends on our common stock. For additional details on the cap on common dividends payable during the current interim gas rate relief period, see Note 3, Uncertainties, "Consumers' Gas Utility Rate Matters - 2003 Gas Rate Case." 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 March 31, 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 $ 1,156 $ 4 $ - Letters of credit Various Various 248 - - Surety bonds and other indemnifications Various Various 27 - - Other guarantees Various Various 212 - - 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 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-74 CMS Energy Corporation The following table provides additional information regarding our guarantees:
Guarantee Description How Guarantee Arose Events That Would Require 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 Standby letters of credit Normal operations of coal power Noncompliance with environmental plants regulations Self-insurance requirement Nonperformance Surety bonds Normal operating activity, permits Nonperformance and license 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 amount and 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 $487 million as of March 31, 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. The off-balance sheet commitments expire as follows:
Commercial Commitments In Millions ------------------------------------------------------------------------------- Commitment Expiration ------------------------------------------------------------------------------- Total 2004 2005 2006 2007 2008 Beyond ------------------------------------------------------------------------------- Off-balance sheet: Guarantees $ 212 $ 6 $ 36 $ 4 $ - $- $ 166 Indemnities 27 8 - - - - 19 Letters of Credit (a) 248 112 108 5 5 5 13 ------------------------------------------------------------------------------- Total $ 487 $ 126 $ 144 $ 9 $ 5 $5 $ 198 ===============================================================================
(a) At March 31, 2004, we had $173 million of cash collateralized letters of credit. The cash that collateralizes the letters of credit is included in Restricted cash on the Consolidated Balance Sheets. CONTINGENTLY CONVERTIBLE SECURITIES: At March 31, 2004, we have 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 initial conversion rate. CMS-75 CMS Energy Corporation 5: EARNINGS PER SHARE AND DIVIDENDS The following table presents the basic and diluted earnings per share computations.
Restated -------------------------------------------------------------------------------------- Three Months Ended March 31 2004 2003 -------------------------------------------------------------------------------------- NET INCOME ATTRIBUTABLE TO COMMON STOCK: CMS Energy - Basic $ (11) $ 82 Add conversion of Trust Preferred Securities (net of tax) - (a) 5 --------------------------- CMS Energy - Diluted $ (11) $ 87 =========================== AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO BASIC AND DILUTED EPS CMS Energy: Average Shares - Basic 161.1 144.1 Add conversion of Trust Preferred Securities - (a) 20.9 Stock Options and Warrants - (b) - --------------------------- Average Shares - Diluted 161.1 165.0 =========================== EARNINGS PER AVERAGE COMMON SHARE Basic $ (0.07) $ 0.57 Diluted $ (0.07) $ 0.52 ======================================================================================
(a) Due to antidilution, the computation of diluted earnings per share excluded the conversion of our 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 March 31, 2004. Effective July 2001, we can revoke the conversion rights if certain conditions are met. (b) Due to antidilution, the computation of diluted earnings per share excluded 0.5 million shares for stock options and warrants for the three months ended March 31, 2004. Computation of diluted earnings per share for the three months ended March 31, 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 since both are "contingently convertible" securities and, as of March 31, 2004, none of the stated contingencies have been met. For additional details, see Note 4, Financings and Capitalization. In January 2003, the Board of Directors suspended the payment of common stock dividends. CMS-76 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 March 31, 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 ------------------------------------------------------------------------------------------------------------- March 31 2004 2003 ------------------------------------------------------------------------------------------------------------- Fair Unrealized Fair Unrealized Cost Value Gain(Loss) Cost Value Gain ------------------------------------------------------------------------------------------------------------- Long-term debt (a) $6,678 $6,985 $(307) $6,134 $6,045 $ 89 Long-term debt - related parties (b) 684 657 27 - - - Trust Preferred Securities (b) - - - 883 640 243 Available for sale securities: Nuclear decommissioning (c) 433 566 133 458 529 71 SERP 54 66 12 55 56 1 ============================================================================================================
(a) Includes a principal amount of $849 million at March 31, 2004 and $917 million at March 31, 2003 relating to current maturities. 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. Company obligated Trust Preferred Securities totaling $663 million that were previously included in mezzanine equity, have been eliminated due to deconsolidation and are reflected in Long-term debt - related parties on the Consolidated Balance Sheets. For additional details, see Note 11, Implementation of New Accounting Standards. In addition, company obligated Trust Preferred Securities totaling $220 million have been converted to Common Stock as of August 2003. (c) On January 1, 2003, we adopted SFAS No. 143 and began classifying our unrealized gains and losses on nuclear decommissioning investments as regulatory liabilities. We previously classified the unrealized gains and losses on these investments in accumulated depreciation. 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, 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, 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, foreign currency, and commodity price risk may be considered CMS-77 CMS Energy Corporation 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. The accounting for changes in the fair value of a derivative (that is, gains or losses) is 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 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. If an active market develops 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. Derivative accounting is required for certain contracts used to limit our exposure to electricity and gas commodity price risk and interest rate risk. The following table reflects the fair value of all contracts requiring derivative accounting:
In Millions -------------------------------------------------------------------------------------------------------------------------- March 31 2004 2003 -------------------------------------------------------------------------------------------------------------------------- Fair Unrealized Fair Unrealized Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss) -------------------------------------------------------------------------------------------------------------------------- Other than trading Electric - related contracts $ - $ - $ - $ 8 $ 1 $ (7) Gas contracts 5 11 6 - - - Interest rate risk contracts - (2) (2) - (27) (27) Derivative contracts associated with Consumers' investment in the MCV Partnership: Prior to consolidation - - - - 17 17 After consolidation: Gas fuel contracts - 81 81 - - - Gas fuel futures - 50 50 - - - Derivative contracts associated with equity investments in: Shuweihat - (33) (33) - (32) (32) Taweelah (35) (33) 2 - (30) (30) Jorf Lasfar - (12) (12) - (11) (11) Other - - - - (4) (4) Trading Electric / gas contracts (3) 15 18 - 7 7 =========================================================================================================================
CMS-78 CMS Energy Corporation The fair value of other than trading derivative contracts is included in either Derivative Instruments or Other Assets on the Consolidated Balance Sheets. The fair value of trading derivative contracts is included in either Price Risk Management Assets or Price Risk Management Liabilities on the Consolidated Balance Sheets. The fair value of derivative contracts associated with our equity investments is included in Enterprises Investments on the 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 the Consolidated Balance Sheets. Effective, January 1, 2003, EITF Issue No. 98-10 was rescinded by EITF Issue No. 02-03 and as a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 can 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. ELECTRIC CONTRACTS: Our electric utility business uses 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. GAS CONTRACTS: Our gas utility business uses fixed price and indexed-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. TRADING ACTIVITIES: CMS ERM accounts for power and gas trading contracts 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 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. We believe that our mathematical models use state-of-the-art technology, pertinent industry data, and prudent discounting in order to forecast certain elongated pricing curves. 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 CMS-79 CMS Energy Corporation risks based on the financial condition of counterparties. We also maintain credit policies that management believes minimize 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. INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk associated with forecasted interest payments on variable-rate debt. Most of our interest rate swaps are designated as cash flow hedges. As such, we record any change in the fair value of 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 any change in the fair value of these contracts in earnings. We have entered into floating-to-fixed interest rate swap agreements to reduce the impact of interest rate fluctuations. The difference between the amounts paid and received under the swaps is accrued and recorded as an adjustment to interest expense over the term of the agreement. We were able to apply the shortcut method to all interest rate swaps that qualified for hedge accounting treatment; therefore, there was no ineffectiveness associated with these hedges. 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 ------------------------------------------------------------------------------- March 31, 2004 $ 26 2005-2006 $ (2) March 31, 2003 $ 462 2003-2007 $ (27) ==============================================================================
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 March 31, 2004 and 5.0 percent at March 31, 2003. Certain equity method investees have issued interest rate swaps, 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. 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 March 31, 2004 and March 31, 2003, we had no outstanding foreign exchange contracts. DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV PARTNERSHIP: Natural 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 CMS-80 CMS Energy Corporation 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. The FASB issued Derivatives Implementation Group Issue C-16, which became effective April 1, 2002, regarding natural gas commodity contracts that combine an option component and a forward component. This guidance requires either that the entire contract be accounted for as a derivative or the components of the contract be separated into two discrete contracts. Under the first alternative, the entire contract considered together would not qualify for the normal purchases and sales exception under the revised guidance. Under the second alternative, the newly established forward contract could qualify for the normal purchases and sales exception, while the option contract would be treated as a derivative under SFAS No. 133 with changes in fair value recorded through earnings. At April 1, 2002, the MCV Partnership had nine long-term gas contracts that contained both an option and forward component. As such, they were no longer accounted for under the normal purchases and sales exception and the MCV Partnership began mark-to-market accounting of these nine contracts through earnings. Based on the natural gas prices, at the beginning of April 2002, the MCV Partnership recorded a $58 million gain for the cumulative effect of this accounting change. During the fourth quarter of 2002, the MCV Partnership removed the option component from three of the nine long-term gas contracts, which should reduce some of the earnings volatility. The MCV Partnership expects future earnings volatility on the six remaining long-term gas contracts that contain volume optionality, since changes to this mark-to-market gain will be recorded on a quarterly basis during the remaining life of approximately four years for these gas contracts. From April 2002 to March 2004, the MCV Partnership recorded an additional net mark-to-market gain of $23 million for these gas contracts for a cumulative mark-to-market gain through March 31, 2004 of $81 million, which will reverse over the remaining life of these gas contracts, ranging from 2004 to 2007. For the three months ended March 31, 2004, the MCV Partnership recorded in Fuel for Electric Generation a $6 million net mark-to-market gain in earnings associated with these contracts. Natural Gas Fuel Futures and Options: 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 and option contracts 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. These financial instruments are derivatives under SFAS No. 133 and the contracts that are used to secure the anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133, since they hedge the price risk associated with the cost of natural gas. 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 CMS-81 CMS Energy Corporation qualify as hedges under SFAS No. 133. Therefore, the resulting mark-to-market gains and losses from cost mitigation activities are flowed through the MCV Partnership's earnings. Cash is deposited with the broker in a margin account at the time futures or options contracts are initiated. The change in market value of these contracts requires adjustment of the margin account balances. The margin account balance as of March 31, 2004 was recorded as a current asset in Prepayments and Other Assets, in the amount of $2 million. For the three months ended March 31, 2004, the MCV Partnership has recognized in other comprehensive income, an unrealized $20 million increase on the futures contracts, which are hedges of forecasted purchases for plant use of market priced gas. This resulted in a net $51 million gain in other comprehensive income as of March 31, 2004. This balance represents natural gas futures with maturities ranging from April 2004 to December 2007, of which $34 million of this gain is expected to be reclassified into earnings within the next twelve months. As of March 31, 2004, Consumers' pretax proportionate share of the MCV Partnership's $51 million net gain recorded in other comprehensive income is $25 million. The MCV Partnership also has recorded, as of March 31, 2004, a $50 million current derivative asset, representing the mark-to-market gain on natural gas futures for anticipated projected electric and steam sales accounted for as hedges. In addition, for the three months ended March 31, 2004, the MCV Partnership has recorded a net $5 million gain in earnings from hedging activities related to natural gas requirements for the MCV Facility operations and a net $1 million gain in earnings from cost mitigation activities. 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. 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." The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years. We made a contribution of $18 million to our 401(h) and VEBA trust funds in March 2004. We plan to make additional contributions of $54 million in 2004. CMS-82 CMS Energy Corporation Costs: The following table recaps the costs incurred in our retirement benefits plans:
In Millions ----------------------------------------------------------------------------- Pension OPEB Three Months Ended March 31 2004 2003 2004 2003 ----------------------------------------------------------------------------- Service cost $ 10 $ 10 $ 5 $ 5 Interest expense 18 20 17 17 Expected return on plan assets (27) (20) (12) (11) Amortization of: Net loss 1 2 6 5 Prior service cost 3 2 (2) (2) ------------------------------- Net periodic pension and postretirement $ 5 $ 14 $ 14 $ 14 =============================================================================
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that was signed into law in December 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. Accounting guidance for the subsidy is not yet available, therefore, we are continuing to defer recognizing the effects of the Act in our 2004 financial statements, as permitted by FASB Staff Position No. 106-b. When accounting guidance is issued, our retiree health benefit obligation may be adjusted. For additional details, see Note 11, Implementation of New Accounting Standards. As of March 31, 2004, we have recorded a prepaid pension asset of $403 million, $20 million of which is in other current assets on our consolidated balance sheets. 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. Net income from these investments included undistributed earnings of $6 million for the three months ended March 31, 2004 and $33 million for the three months ended March 31, 2003. The most significant of these investments is our 50 percent interest in Jorf Lasfar, our 45 percent interest in SCP, and our 40 percent interest in Taweelah. Listed below is the summarized income statement information for our most significant equity method investments. Income Statement Data
In Millions ---------------------------------------------------------------------------------- Jorf Three Months Ended March 31, 2004 Lasfar SCP Taweelah Total ---------------------------------------------------------------------------------- Operating revenue $ 110 $ 19 $ 22 $151 Operating expenses 65 5 10 80 ------------------------------------------ Operating income 45 14 12 71 Other expense, net 15 7 25 47 ------------------------------------------ Net income (loss) $ 30 $ 7 $(13) $ 24 =================================================================================
CMS-83 CMS Energy Corporation
In Millions ------------------------------------------------------------------------------ Jorf Three Months Ended March 31, 2003 Lasfar SCP Taweelah Total ----------------------------------------------------------------------------- Operating revenue $ 90 $ 12 $ 23 $ 125 Operating expenses 43 4 9 56 ---------------------------------------- Operating income 47 8 14 69 Other expense, net 19 4 2 25 ---------------------------------------- Net income $ 28 $ 4 $ 12 $ 44 ============================================================================
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 Michigan through our subsidiary, Consumers. The gas utility segment consists of regulated activities like 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 tables below show 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 ---------------------------------------------------------------------------------------- Restated ---------------------------------------------------------------------------------------- Three Months Ended March 31 2004 2003 ---------------------------------------------------------------------------------------- Electric utility $ 630 $ 650 Gas utility 905 789 Enterprises 219 529 ------------------- $ 1,754 $ 1,968 ========================================================================================
NET INCOME (LOSS) In Millions ---------------------------------------------------------------------------------------- Restated ---------------------------------------------------------------------------------------- Three Months Ended March 31 2004 2003 ---------------------------------------------------------------------------------------- Electric utility $ 45 $ 51 Gas utility 55 54 Enterprises (61) 21 Other (50) (44) ------------------ $ (11) $ 82 ========================================================================================
TOTAL ASSETS In Millions ---------------------------------------------------------------------------------------- Restated ---------------------------------------------------------------------------------------- March 31 2004 2003 ---------------------------------------------------------------------------------------- Electric utility $ 6,891 $ 6,749 Gas utility 2,637 2,410 Enterprises 4,915 5,622 Other 674 420 -------------------- $ 15,117 $ 15,201 ========================================================================================
CMS-84 CMS Energy Corporation 10: ASSET RETIREMENT OBLIGATIONS SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: 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: - $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 ARO liability would increase by $22 million. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as 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. There is a low probability of a retirement date, so no liability has been recorded for these assets. 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 are based largely on 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-85 CMS Energy Corporation The following tables describe our assets that have legal obligations to be removed at the end of their useful life.
March 31, 2004 In Millions -------------------------------------------------------------------------------------------------------- In Service Trust ARO Description Date Long Lived Assets Fund -------------------------------------------------------------------------------------------------------- Palisades-decommission plant site 1972 Palisades nuclear plant $497 Big Rock-decommission plant site 1962 Big Rock nuclear plant 69 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 - ========================================================================================================
March 31, 2004 In Millions ---------------------------------------------------------------------------------------------------- ARO Liability ARO ---------------- Cash Flow Liability ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 3/31/04 ---------------------------------------------------------------------------------------------------- Palisades-decommission $249 $268 $ - $ - $ 5 $31 $304 Big Rock-decommission 61 35 - (21) 3 22 39 JHCampbell intake line - - - - - - - Coal ash disposal areas 51 52 - - 1 - 53 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 $ - $ (21) $10 $53 $401 ====================================================================================================
(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. 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 obligations have been accrued through depreciation charges. We estimate that we had $1.005 billion at March 31, 2004 and $937 million at March 31, 2003 of previously accrued asset removal costs related to our regulated operations, for 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. 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. On December 24, 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. CMS-86 CMS Energy Corporation 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. In addition, 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 $718 million at March 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.471 billion at March 31, 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 $120 million at March 31, 2004. Property, plant, and equipment serving as collateral for these obligations have a carrying value of $171 million. 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, and have not, restated 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 chart below details our involvement in these entities at March 31, 2004: CMS-87 CMS Energy Corporation
Name (Ownership Nature of the Involvement Investment Balance Operating Agreement Total Generating Interest) Entity Country Date (In Millions) with CMS Energy Capacity ----------------------------------------------------------------------------------------------------------------------------------- Taweelah (40%) Power Generator United Arab 1999 $ 75 Yes 777 MW Emirates Generator - Under Jubail (25%) Construction Saudi Arabia 2001 $ - Yes 250 MW Generator - Under United Arab Shuweihat (20%) Construction Emirates 2001 $(30) (a) Yes 1,500 MW -------------------------------------------------------------------------------------------------------------------------------- Total $ 45 2,527 MW ================================================================================================================================
(a) At March 31, 2004, we carried a negative investment in Shuweihat. The balance is comprised of our investment of $3 million reduced by our proportionate share of the negative fair value of derivative instruments of $33 million. We are required to record the negative investment due to our future commitment to make an equity investment in Shuweihat. Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $45 million, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $129 million, including a letter of credit relating to our required initial investment in Shuweihat of $70 million. We plan to contribute our initial investment when the project becomes commercially operational in 2004. In April 2004, we sold our investment in Loy Yang. In March 2004, we recorded an $81 million after-tax impairment charge. For additional information regarding the Loy Yang sale, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. EITF ISSUE NO. 02-03, RECOGNITION AND REPORTING OF GAINS AND LOSSES ON ENERGY TRADING CONTRACTS UNDER EITF ISSUES NO. 98-10 AND 00-17: At its October 25, 2002 meeting, the EITF reached a consensus to rescind EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. Energy trading contracts that do not meet the definition of a derivative must be accounted for as executory contracts. We recognized a loss for the cumulative effect of change in accounting principle of $23 million, net of tax, during the three-month period ended March 31, 2003. ACCOUNTING STANDARDS NOT YET EFFECTIVE PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, 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 (Act), that was signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy 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, CMS-88 CMS Energy Corporation as permitted by FASB Staff Position, No. SFAS 106-1. Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No. 106-1 and provides further guidance for accounting for the Act. Proposed FASB Staff Position, No. 106-b states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations (APBO) and postretirement benefit costs should reflect the effects of the Act. As of March 31, 2004, we have not determined whether our postretirement benefit plan is actuarially equivalent to Medicare Part D. Therefore, our measures of APBO and net periodic postretirement benefit cost do not reflect any amount associated with the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. If our prescription drug plan is determined to be actuarially equivalent to Medicare Part D, we estimate a decrease in OPEB expense of approximately $23 million for 2004 and a one-time reduction of our benefit obligation of approximately $150 million, to be amortized over future periods. This Proposed FASB Staff Position would be effective for the first interim or annual period beginning after June 15, 2004. CMS-89 CMS Energy Corporation (This page intentionally left blank) CMS-90 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 purchase, transport, store, distribute, and sell 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 refocusing 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 in 2003, we face important challenges in the future. We continue to lose industrial and commercial customers to other electric suppliers without receiving compensation for stranded costs caused by the lost sales. As of April 2004, we lost 823 MW or 10 percent of our electric business to these alternative electric suppliers. We expect the loss to grow to over 1,100 MW in 2004. 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 work cooperatively with the MPSC to resolve this issue. Further, higher natural gas prices have harmed the economics of the MCV and we are seeking approval from the MPSC to change the way in which the facility is used. Our proposal would reduce gas consumption by an estimated 30 to 40 bcf per year while improving the MCV'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 critical for our shareowners and customers. We also are focused on further reducing our business, financial, and regulatory risks, while growing the equity base of our company. Finally, we are planning to devote more attention to improving business growth. Our business plan is targeted at predictable earnings growth. The result of these efforts will be a strong, reliable utility company that will be poised to take advantage of opportunities for further growth. CE-1 Consumers Energy Company 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 their assets, liabilities, and activities into our financial statements for the first time as of and for the quarter ended March 31, 2004. The MCV Partnership and the FMLP were previously reported as equity method investments. Therefore, the consolidation of these entities had no impact on our consolidated net income. 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 in Rule 3b-6 of the Securities Exchange Act of 1934, as amended, Rule 175 of the Securities Act of 1933, as amended, and relevant legal decisions. 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 on the Pension Plan, interest rates and 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, - securities 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, - ability to access the capital markets successfully, - international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments, - adverse regulatory or legal decisions, including environmental laws and regulations, - 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, and proposals by the FERC to change the way public utilities and natural gas companies, and their subsidiaries and affiliates, interact with each other, - energy markets, including the timing and extent of unanticipated 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, CE-2 Consumers Energy Company - 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 CMS Energy's or our 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 NET INCOME AVAILABLE TO COMMON STOCKHOLDER
In Millions ----------------------------------------------------------------- March 31 2004 2003 Change ----------------------------------------------------------------- Three months ended $101 $99 $2 =================================================================
2004 COMPARED TO 2003: For the three months ended March 31, 2004, our net income increased $2 million versus 2003 for several reasons. Higher gas tariff rates, as authorized by the interim MPSC gas rate order issued in December 2003 increased net income by $6 million. This interim order authorized the reduction of gas depreciation rates as well, decreasing depreciation expense compared to the same period in 2003. Electric depreciation expense also decreased versus 2003 because in 2004, we were able to defer depreciation on the excess of capital expenditures over our depreciation base and recognize interest income on the excess capital expenditures as authorized by the Customer Choice Act. These reductions to depreciation and the additional interest income, along with a decrease in nuclear operating costs increased net income by $7 million in the first quarter of 2004. Nuclear operating costs for the first quarter of 2004 decreased compared to the same period in 2003, because of a scheduled refueling outage that began in March 2003. Further contributing to increased net income for the first quarter 2004 versus 2003 was a reduction to general tax expense of $3 million due to decreased MSBT expense, and a $1 million increase in gas wholesale and retail services relating to gas transportation and storage services. CE-3 Consumers Energy Company The increase in net income for the first quarter of 2004 versus the first quarter of 2003 also reflects a 2003 charge of $12 million to non-utility expense that recognized a decline in the market value of CMS Energy stock we held. Partially offsetting these increases to net income were reductions to net income attributable to decreases in gas and electric deliveries, increased interest charges, and lower electric power cost recovery revenues compared to the same period in 2003. Milder weather in the first quarter of 2004 decreased gas deliveries, reducing net income by $9 million. The weather also had an adverse effect on electric deliveries, and along with a reduction to the electric tariff rates and the continued loss of industrial customers switching to other electric suppliers, decreased net income by $7 million in the first quarter of 2004 versus 2003. Increased costs of borrowing reduced 2004 net income by $6 million, reflecting higher levels of debt. Finally, electric power supply revenues in excess of electric power supply costs were reserved in 2004 for possible refund to customers and did not benefit net income as in 2003. In 2003, our recovery of power supply costs was fixed as required under the Customer Choice Act. This change decreased net income $4 million in the first quarter of 2004 versus 2003. For additional details, see "Electric Results of Operations" and "Gas Results of Operations" within this section and Note 2, Uncertainties. ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions ------------------------------------------------------------------------------- March 31 2004 2003 Change ------------------------------------------------------------------------------- Three months ended $45 $51 $ (6) === === ====== Reasons for the change: Electric deliveries $ (10) Power supply costs and related revenue (6) Other operating expenses and non-commodity revenue 10 General taxes 4 Fixed charges (6) Income taxes 2 ------ Total change $ (6) ==============================================================================
ELECTRIC DELIVERIES: Electric deliveries, including transactions with other wholesale marketers, other electric utilities, and customers choosing alternative suppliers increased 0.3 billion kWh or 3.6 percent in the first quarter of 2004 compared to 2003. Despite increased electric deliveries, electric delivery revenue decreased in the first quarter of 2004 versus 2003. This revenue decrease primarily reflects tariff revenue reductions that began January 1, 2004. The tariff revenue reductions were equivalent to the Big Rock nuclear decommissioning surcharge in effect when our electric retail rates were frozen from June 2000 through December 31, 2003. The tariff revenue reduction decreased electric delivery revenue by $9 million in the first quarter of 2004 versus 2003, and is expected to decrease electric delivery revenues $35 million in 2004 versus 2003. CE-4 Consumers Energy Company The reduction in electric delivery revenue for the first quarter 2004 versus 2003 also reflects the impact of customers switching to alternative electric suppliers as allowed by the Customer Choice Act. Although deliveries to the sector of customers choosing an alternative supplier has grown significantly from the same period in 2003, the margin on these sales is substantially less than if we had supplied the generation. POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost rate of recovery 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 revenues had been less than actual power supply costs, the impact 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 revenues are in excess of actual power supply costs, this former benefit is reserved for possible future refund. This change in the treatment of excess power supply revenues over power supply costs decreased 2004 versus 2003 first quarter operating income. OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In the first quarter of 2004, other operating expenses decreased $2 million and non-commodity revenue increased $8 million versus 2003. The increase in non-commodity revenue relates primarily to interest income recognized in relation to capital expenditures in excess of depreciation as allowed by the Customer Choice Act. The decrease in operating expenses reflects a reduction in nuclear operating and maintenance expense in 2004 compared to the same period in 2003 that included a scheduled refueling outage at the Palisades nuclear facility. GENERAL TAXES: In the first quarter of 2004, general taxes decreased from the same period in 2003 due primarily to reductions in MSBT expense. FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004 versus the same period in 2003 due to higher average debt levels, partially offset by a 41 basis point reduction in the average interest rate. INCOME TAXES: In the first quarter of 2004, income taxes decreased versus the same period in 2003 due primarily to lower earnings by the electric utility. CE-5 Consumers Energy Company GAS UTILITY RESULTS OF OPERATIONS
In Millions --------------------------------------------------------------------------------------- March 31 2004 2003 Change --------------------------------------------------------------------------------------- Three months ended $55 $54 $ 1 === === ======= Reasons for the change: Gas deliveries $ (14) Gas rate increase 9 Gas wholesale and retail services and other gas revenues 2 Operation and maintenance (4) General taxes, depreciation, and other income 6 Fixed charges (3) Income taxes 5 ------- Total change $ 1 =======================================================================================
GAS DELIVERIES: For the first quarter 2004 versus the same period in 2003, gas deliveries, including miscellaneous transportation, decreased 7 bcf or 4 percent versus 2003. Deliveries decreased during the first quarter of 2004 due primarily 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, first quarter 2004 gas revenues increased compared to the same period in 2003. GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: Gas wholesale and retail services and other gas revenues increased for the period ended March 31, 2004 versus the same period in 2003. This increase relates primarily to increases in gas transportation and storage revenues and late payment fees. In 2003, we reserved $11 million for a settlement agreement associated with the 2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003 through February 2004, at Consumers' authorized rate of return, increased the cost of the settlement by $1 million. In March 2004, the MPSC approved this settlement agreement in the amount we had reserved. Neither the prior year reservation, nor the current year final MPSC settlement had any effect on earnings in the first quarter of 2004 versus the same period in 2003. OPERATION AND MAINTENANCE: In the first quarter 2004 versus 2003, operation and maintenance expenses increased due to increases in health care costs and additional expenditures on safety, reliability, and customer service. GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In the first quarter 2004 versus 2003, the net change in general tax expense, depreciation expense, and other income increased operating income primarily because of decreases in depreciation rates authorized by the MPSC's December 2003 interim rate order. FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004 versus the same period in 2003 due to higher average debt levels, partially offset by a 41 basis point reduction in the average interest rate. CE-6 Consumers Energy Company INCOME TAXES: Income tax expense decreased in the period ended March 31, 2004 versus the same period in 2003. This reduction was attributable primarily to the income tax treatment of items related to plant, property and equipment as required by past MPSC rulings. CRITICAL ACCOUNTING POLICIES The following accounting policies are important to an understanding of our results 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 regulatory accounting, - 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. 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 past 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 power purchase agreement 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 power purchase agreement 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 CE-7 Consumers Energy Company 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 power purchase agreement. 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. Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned in our coal plants and our operations 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, while the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been affected adversely. 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 harmed. In February 2004, we filed a resource conservation plan 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 natural gas consumption 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 April 2004, the presiding ALJ at the MPSC held a pre-hearing conference regarding the resource conservation plan. The ALJ denied our request to establish a schedule that would have allowed consideration of the plan on an interim basis and established a review schedule that calls for a Proposal for Decision in September 2004 after which point the MPSC would consider the plan. We cannot predict if or when the MPSC will approve our resource conservation plan. 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 22 years and the MPSC's decision in 2007 or beyond related to limiting our recovery of capacity and fixed energy payments. Natural gas prices have been volatile historically. Presently, there is no consensus in the marketplace on the price or range of prices of natural gas in the short term or beyond the next five years. Even with an approved resource conservation plan, 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, see Note 2, Uncertainties, "Other Electric Uncertainties - The Midland Cogeneration Venture." CE-8 Consumers Energy Company ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity. For example, 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 March 31, 2004, we had $1.125 billion recorded as regulatory assets and $1.497 billion recorded as regulatory liabilities. For additional details on industry regulation, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." 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 securities. 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 and 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 reported as regulatory liabilities. The fair value of these investments is determined from quoted market prices. Our debt securities are classified as held-to-maturity securities and are reported at cost. 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. The accounting for changes in the fair value of a derivative (that is, gains or losses) is reported either in earnings or accumulated other comprehensive income depending on whether the derivative qualifies for special hedge accounting treatment. For additional details on the accounting policies for derivative instruments, see Note 4, Financial and Derivative Instruments. The types of contracts we typically classify as derivative instruments are interest rate swaps, electric call options, gas fuel futures and 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. CE-9 Consumers Energy Company 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. If an active market develops 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. 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, volatilities, interest rates, and exercise periods. Changes in forward prices or volatilities could change significantly the calculated fair value of certain contracts. At March 31, 2004, we assumed a market-based interest rate of 1 percent (a rate that is not significantly different than the LIBOR rate) and an average volatility rate of 66.8 percent to calculate the fair value of our gas options. At March 31, 2004, we assumed market-based interest rates ranging between 1.09 percent and 2.7 percent and volatility rates ranging between 23 percent and 38 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 "Equity 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. CE-10 Consumers Energy Company Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in market interest rates):
In Millions ------------------------------------------------------------------------------------------------------ March 31, December 31, 2004 2003 ------------------------------------------------------------------------------------------------------ Variable-rate financing - before tax annual earnings exposure $ 1 $ 1 Fixed-rate financing - potential loss in fair value (a) 154 154 ======================================================================================================
(a) Fair value exposure could only be realized if we repurchased all of our fixed-rate financing. As discussed in "Electric Business Uncertainties - Competition and Regulatory Restructuring - Securitization" within this MD&A, we have filed an application with the MPSC to securitize certain expenditures. Upon final approval, we intend to use the proceeds from the Securitization to retire higher-cost debt, which could include a portion of our current fixed-rate debt. We do not believe that any adverse change in debt price and interest rates would have a material adverse effect on either our consolidated financial position, results of operations, or cash flows. 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 used 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. Electric call options give us the right, but not the obligation, to purchase electricity at predetermined fixed prices. Weather-based gas supply call options, along with the gas supply call and put options, are used to purchase reasonably priced gas supply. Gas supply call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Gas supply put options give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices. At March 31, 2004, we only held gas supply call and 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, thus, are treated as derivative instruments. Also, the MCV Partnership enters into natural gas futures contracts 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. CE-11 Consumers Energy Company Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
In Millions -------------------------------------------------------------------------------------------------- March 31, December 31, 2004 2003 ------------------------------------------------------------------------------------------------- Potential reduction in fair value: Gas supply call and put option contracts $12 $ 1 Derivative contracts associated with Consumers' investment in the MCV Partnership: Gas fuel contracts 24 N/A Gas fuel futures 25 N/A ================================================================================================
During the first quarter of 2004, we entered into additional gas supply call and put option contracts. As a result, the potential reduction in the fair value increased from December 31, 2003 as shown in the table above. 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 further discussed in Note 7, Implementation of New Accounting Standards. Equity 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 and 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 reported as regulatory liabilities. 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 ---------------------------------------------------------------- March 31, December 31, 2004 2003 ---------------------------------------------------------------- Potential reduction in fair value: Nuclear decommissioning investments $56 $57 Other available for sale investments 4 4 ================================================================
For additional details on market risk and derivative activities, see Note 4, Financial and Derivative Instruments. CE-12 Consumers Energy Company 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. 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 expense, OPEB expense, and cash contributions for the next three years:
Expected Costs In Millions --------------------------------------------------------------------------------------- Pension Expense OPEB Expense Contributions --------------------------------------------------------------------------------------- 2004 $20 $54 $ 125 2005 52 62 114 2006 71 58 106 =======================================================================================
Actual future pension expense 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 March 31, 2004, we have a prepaid pension asset of $379 million recorded 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 expense 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 expense for 2004 by $4 million. The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that was signed into law in December 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We are continuing to defer recognizing the effects of the Act in our 2004 financial statements, as permitted by FASB Staff Position No. 106-b. When accounting guidance is issued, our retiree health benefit obligation may be adjusted. CE-13 Consumers Energy Company 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, Accounting for Asset Retirement Obligations, 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 a regulatory asset and liability 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 the asset retirement obligation is incurred, such as 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. There is a low probability of a retirement date, so no liability has been recorded for these assets. 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 are based largely on third-party cost estimates. For additional details on ARO, see Note 6, 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 balance sheet. 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 CE-14 Consumers Energy Company 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, 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, - purchases and sales of electricity and gas for generation 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 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. We determined that the MCV Partnership and the FMLP are variable interest entities and that we are the primary beneficiary of these entities. Therefore, we have consolidated these partnerships into our consolidated financial statements for the first time as of and for the quarter ended March 31, 2004. 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. CE-15 Consumers Energy Company In 2003, we had debt maturities and capital expenditures that required substantial amounts of cash. As a result, we executed a financial improvement plan to address these critical liquidity issues. We explored financing opportunities, such as refinancing debt and issuing new debt. We also reduced capital expenditures. In 2004, we will continue to monitor our operating expenses and capital expenditures and evaluate market conditions for financing opportunities. We believe that our current level of cash and borrowing capacity, along with anticipated cash flows from operating activities, and reduced capital expenditures, will be sufficient to meet our liquidity needs through 2005. CASH POSITION, INVESTING, AND FINANCING SUMMARY OF CASH FLOWS:
In Millions ---------------------------------------------------------------------------------- Three Months Ended March 31 2004 2003 ---------------------------------------------------------------------------------- Net cash provided by (used in): Operating activities $ 263 $ 396 Investing activities (112) (118) Financing activities (88) (51) -------------- Net Increase in Cash and Cash Equivalents $ 63 $ 227 ==================================================================================
OPERATING ACTIVITIES: For the three months ended March 31, 2004, net cash provided by operating activities decreased $133 million due to a greater increase in accounts receivable and accrued revenue of $284 million primarily due to lower sales of accounts receivable resulting from our improved liquidity. This change was offset by a greater decrease in gas inventory of $99 million resulting from sales at higher prices combined with lower volumes of gas purchased. INVESTING ACTIVITIES: For the three months ended March 31, 2004, net cash used in investing activities decreased $6 million primarily due to a decrease in 2004 versus 2003 capital expenditures of $4 million as a result of our strategic plan to reduce capital expenditures and an increase in proceeds from nuclear decommissioning trust funds of $14 million. These changes were partially offset by a decrease in asset sale proceeds of $13 million resulting from 2003 asset sales. FINANCING ACTIVITIES: For the three months ended March 31, 2004, net cash used in financing activities increased $37 million primarily due to a decrease of $48 million in net proceeds from borrowings. For additional details on long-term debt activity, see Note 3, Financings and Capitalization. CE-16 Consumers Energy Company OBLIGATIONS AND COMMITMENTS Our total contractual obligations as of March 31, 2004, are shown in the following table.
Contractual Obligations In Millions -------------------------------------------------------------------------------------------------------------------- Payments/Expiration --------------------------------------------------------- 2009 and Total 2004 2005 2006 2007 2008 beyond -------------------------------------------------------------------------------------------------------------------- On-balance sheet: Long-term debt $ 4,015 $ 136 $ 559 $ 478 $ 59 $ 504 $ 2,279 Long-term debt - related parties 506 - - - - - 506 Notes payable - related parties 200 200 - - - - - Capital lease obligations 372 44 31 27 26 26 218 -------------------------------------------------------------------------------------------------------------------- Total on-balance sheet $ 5,093 $ 380 $ 590 $ 505 $ 85 $ 530 $ 3,003 -------------------------------------------------------------------------------------------------------------------- Off-balance sheet: Operating leases $ 64 $ 9 $ 8 $ 7 $ 6 $ 5 $ 29 Long-term service agreements 219 9 12 19 13 12 154 Unconditional purchase obligations 9,154 1,648 1,226 781 582 508 4,409 -------------------------------------------------------------------------------------------------------------------- Total off-balance sheet $ 9,437 $ 1,666 $ 1,246 $ 807 $ 601 $ 525 $ 4,592 ====================================================================================================================
For additional details, see Note 2, Uncertainties, and Note 3, Financings and Capitalization. REGULATORY AUTHORIZATION FOR FINANCINGS: We issue short and long-term securities under the FERC authorization. For additional details of our existing authorization, see Note 3, Financings and Capitalization. LONG-TERM DEBT: Details on our long-term debt are presented in Note 3, Financings and Capitalization. SHORT-TERM FINANCINGS: At March 31, 2004, we have $376 million available under a revolving credit facility that is available for general corporate purposes, working capital, and letters of credit. The MCV Partnership has a $50 million working capital facility available. CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of the leased portion of the MCV Partnership facility, leased service vehicles, and leased office furniture. The full obligation of our leases could become due in the event of lease payment default. OFF-BALANCE SHEET ARRANGEMENTS: We use off-balance sheet arrangements in the normal course of business. Our off-balance sheet arrangements include: - operating leases, - long-term service agreements, - sale of accounts receivable, and - unconditional purchase obligations. Operating Leases: Leases of railroad cars are accounted for as operating leases. Long-term Service Agreements: These obligations of the MCV Partnership represent the cost of the current MCV Facility maintenance service agreements and cost of spare parts. 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. CE-17 Consumers Energy Company Unconditional Purchase Obligations: Long-term contracts for purchase of commodities and services are unconditional purchase obligations. These obligations represent operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include: - natural gas, - electricity, - coal purchase contracts and their associated cost of transportation, and - electric transmission. Included in unconditional purchase obligations are long-term power purchase agreements with various generating plants. These contracts require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $13 million per month during 2004. If a plant is not available to deliver electricity, we are not obligated to make the capacity payments to the plant for that period of time. For additional details on power supply costs, see "Electric Utility Results of Operations" within this MD&A and Note 2, Uncertainties, "Electric Rate Matters - Power Supply Costs." COMMERCIAL COMMITMENTS: Our commercial 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. Our commercial commitments at March 31, 2004 are as follows:
Commercial Commitments In Millions --------------------------------------------------------------------------------------------------------------- Commitment Expiration -------------------------------------------------------- 2009 and Total 2004 2005 2006 2007 2008 beyond ---------------------------------------------------------------------------------------------------------------- Off-balance sheet: Indemnities $ 8 $ 8 $ - $ - $ - $ - $ - Letters of credit 24 8 16 - - - - ================================================================================================================
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at March 31, 2004, we had $397 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. We are also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. In February 2004, we paid $78 million in common stock dividends to CMS Energy. For additional details on the cap on common dividends payable during the current interim gas rate relief period, see Note 2, Uncertainties, "Gas Rate Matters - 2003 Gas Rate Case." CE-18 Consumers Energy Company 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 abnormal 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 project electric deliveries to grow approximately two percent. This short-term outlook for 2004 assumes higher levels of manufacturing activity than in 2003 and normal weather conditions during the remainder of the year. 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 being followed by the MPSC, - recovery of electric restructuring implementation costs, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer instead of an electric transmission owner-operator. Regulatory - effects of conclusions about the causes of the August 14, 2003 blackout, including exposure to liability, increased regulatory requirements, and new legislation, - successful implementation of initiatives to reduce exposure to purchased power price increases, - effects of potential performance standards payments, - effects of the FERC supply margin assessment requirements for electric market-based rate authority, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, and CE-19 Consumers Energy Company - 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 and coal, - pending litigation filed by PURPA qualifying facilities, - pending other litigation, and - potential rising pension costs due to market losses and lump sum payments. For additional details, see "Accounting for Pension and OPEB" within this MD&A. 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 $771 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 8.9 percent. As of March 31, 2004, we have incurred $469 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 2009. These expenditures include installing catalytic reduction technology on coal-fired electric plants. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost of these credits is estimated to average $8 million per year and 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. The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which requires 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 required to reduce nitrogen oxide emissions 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, through the installation of flue gas desulfurization scrubbers and selective catalytic reduction units. 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. CE-20 Consumers Energy Company Several bills have been introduced in the United States Congress that would require carbon dioxide emissions reduction. We cannot predict whether any federal mandatory carbon dioxide emissions reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that emissions reduction rules come into legal 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 April 2004, alternative electric suppliers are providing 823 MW of generation supply to ROA customers. This amount represents 10 percent of our distribution load and an increase of 50 percent compared to April 2003. We anticipate this upward trend to continue and expect over 1,100 MW of generation supply to ROA customers in 2004. We cannot predict the total amount of electric supply load that may be lost to competitor suppliers. In February 2004, the MPSC issued an order on Detroit Edison's request for rate relief for costs associated with customers leaving under electric customer choice. The MPSC order allows Detroit Edison to implement a transition charge on ROA customers and eliminates securitization charge offsets. We are seeking similar recovery of Stranded Costs due to ROA customers leaving our system and are encouraged by this ruling. We cannot predict if or when the MPSC will approve implementation of a transition charge on our ROA customers. Securitization: In March 2003, we filed an application with the MPSC seeking approval to issue Securitization bonds. In June 2003, the MPSC issued a financing order authorizing the issuance of Securitization bonds in the amount of approximately $554 million. In July 2003, we filed for rehearing and clarification on a number of features in the financing order. In December 2003, the MPSC issued its order on rehearing, which rejected our requests for clarification and modification to the dividend payment restriction, failed to rule directly on the accounting clarifications requested, and remanded the proceeding to the ALJ for additional proceedings to address rate design. We filed testimony regarding the remanded proceeding in February 2004. The ALJ completed hearings in March 2004 and the MPSC decision is not anticipated before May 2004, but could be later. The financing CE-21 Consumers Energy Company order will become effective after our acceptance of a favorable MPSC order. Bonds will not be issued until resolution of any appeals. 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 adopted by the MPSC will be applied in a manner that will fully offset any associated margin loss. In 2002 and 2001, the MPSC issued orders finding that we experienced zero net Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous issues regarding the net Stranded Cost methodology in a way that would allow a reliable prediction of the level of Stranded Costs for future years. We currently are in the process of appealing these orders with the Michigan Court of Appeals and the Michigan Supreme Court. In March 2003, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2002, and for approval of a net Stranded Cost recovery charge. Our net Stranded Costs incurred in 2002, including the cost of money, are estimated to be $47 million with the issuance of Securitization bonds that include Clean Air Act investments, or $104 million without the issuance of Securitization bonds that include Clean Air Act investments. Once the MPSC issues a final financing order on Securitization, we will know the amount of our request for net Stranded Cost recovery for 2002. In April 2004, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2003, including the cost of money, in the amount of $106 million with the issuance of Securitization bonds that include Clean Air Act investments, or $165 million without the issuance of Securitization bonds that include Clean Air Act investments. Similar to the request that was granted by the MPSC for Detroit Edison, we also requested interim relief for 2002 and 2003 net Stranded Costs. We cannot predict how the MPSC will rule on our requests for the recoverability of Stranded Costs. Therefore, we have not recorded regulatory assets to recognize the future recovery of such costs. Implementation Costs: Since 1997, we have incurred significant costs to implement the Customer Choice Act. The Customer Choice Act allows electric utilities to recover the Act's implementation costs. The MPSC reviewed and granted deferred conditional recovery of certain of the implementation costs incurred through 2001, but has not yet authorized rates that would allow recovery. Our applications for $7 million of implementation costs for 2002 and $1 million for 2003 are currently pending approval by the MPSC. Included in the 2002 request is $5 million related to our former participation in the development of the Alliance RTO. As of March 31, 2004, implementation costs totaled $93 million, which includes $23 million associated with the cost of money. We believe the implementation costs and the associated cost of money are fully recoverable in accordance with the Customer Choice Act. Cash recovery from customers is expected to begin after rate cap periods expire. For additional information on rate caps, see "Rate Caps" within this section. In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision finding that the recovery of 1999 implementation costs is conditional and subject to later disallowance is unlawful. The case was remanded to the MPSC. The MPSC issued an order regarding the remanded proceeding that directed us to choose whether we prefer to recover our approved implementation costs through Securitization pursuant to the MPSC's final order in the Securitization proceeding or whether we would prefer to have recovery controlled by the remand proceeding. If the latter option was chosen, the MPSC indicated that it intended to authorize recovery of such implementation costs through the use of surcharges on all customer classes that coincide with the expiration of the Customer Choice Act rate caps. We chose recovery of the approved implementation costs through the use of surcharges and withdrew our request for approved implementation costs recovery from our Securitization proposal. The implementation costs withdrawn from the Securitization case were incurred for the years 1998 through 2000. In the filing we made electing recovery through separate surcharges, we requested approval of surcharges that would allow recovery of implementation costs incurred for the years 1998 through 2001. We requested that the Court of Appeals issue similar remand orders with respect to appeals of the MPSC orders addressing 2000 and 2001 implementation costs. We cannot predict the amounts the MPSC will approve as recoverable costs. CE-22 Consumers Energy Company Also, we are pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million in certain electric utility restructuring implementation costs related to our former participation in the development of the Alliance RTO, a portion of which has been expensed. In May 2003, the FERC issued an order denying the MISO's request for authorization to reimburse us. We appealed the FERC ruling at the United States Court of Appeals for the District of Columbia. We also requested that the MISO seek authorization to reimburse the METC for these development costs. The MISO filed this request but the FERC denied it. While we appeal the FERC's orders, we are also pursuing other potential means of recovery, such as recovery of Alliance RTO development costs at the MPSC. We cannot predict the outcome of the appeal process or the ultimate amount, if any, we will collect for Alliance RTO development costs. Security Costs: The Customer Choice Act allows for recovery of new and enhanced security costs, as a result of federal and state regulatory security requirements. All retail customers, except customers of alternative electric suppliers, would pay these charges. In April 2004, we filed a security cost recovery case with the MPSC for $25 million of cost that regulatory treatment has not yet been granted through other means. The costs are for enhanced security and insurance because of federal and state regulatory security requirements imposed after the September 11, 2001 terrorist attacks. We cannot predict how the MPSC will rule on our requests for the recoverability of security costs. 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 make it impossible for us to fully recover 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 assures 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. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $30 million in 2004. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. The revenues received from the PSCR charge are also subject to subsequent reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of this filing. Decommissioning Surcharge: When our electric retail rates were frozen in June 2000, a nuclear decommissioning surcharge related to the decommissioning of Big Rock was included. In December 2000, funding of the Big Rock nuclear decommissioning trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. However, we continued to collect the CE-23 Consumers Energy Company equivalent to the Big Rock nuclear decommissioning surcharge consistent with the Customer Choice Act rate freeze through December 31, 2003. Collection of the surcharge stopped, effective January 1, 2004, when the electric rate freeze expired. Industrial Contracts: We entered into multi-year electric supply contracts with certain large industrial customers. The contracts provide electricity at specially negotiated prices, usually at a discount from tariff prices. The MPSC approved these special contracts totaling approximately 685 MW of load. Unless terminated or restructured, the majority of these contracts are in effect through 2005. As of March 31, 2004, contracts for 201 MW of load have terminated. Of the contracts that have terminated, 70 MW of load have gone to an alternative electric supplier and 131 MW of load have returned to bundled tariff rates. In January 2004, new special contracts for 91 MW, with the State of Michigan and three universities, were approved by the MPSC. Initial special contracts with Dow Corning and Hemlock Semi-Conductor were terminated in December 2003. New special contracts with Dow Corning and Hemlock Semi-Conductor for 101 MW received interim approval from the MPSC and are awaiting final approval. As of April 2004, our special contracts total approximately 580 MW of load. All new special contracts end by January 1, 2006. We cannot predict whether additional special contracts will be necessary, advisable, or approved. Transmission Sale: 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. We cannot predict whether the remaining open items will affect materially the sale proceeds previously recognized. 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. The financial impact of such proceedings, rulemaking, and trends are not quantifiable currently. In addition, we are evaluating whether or not there may be impacts on electric reliability associated with the outcomes of these various transmission related proceedings. For example, in April 2004, Commomwealth Edison Company received approval from the FERC to join into the PJM RTO effective May 1, 2004. This integration could create different patterns of flow and power within the Midwest area and affect adversely our ability to provide reliable service to our customers. 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. In December 2003, the MPSC issued an order requiring Michigan investor-owned utilities to file reports by April 1, 2004, on the status of the transmission and distribution lines used to serve their customers, including details on vegetation trimming practices in calendar year 2003. We complied with the MPSC's order. In February 2004, the Board of Trustees of the NERC approved recommendations to improve electric transmission reliability. In April 2004, the U.S. and Canadian Power System Outage Task Force released its final report on the causes and recommendations surrounding the blackout. The Task Force concluded that inadequate assessment of voltage instability and vulnerability by First Energy; inadequate CE-24 Consumers Energy Company communication between interconnected grid operators; and improper vegetation management, outside of our operating territory, were the key causes of the blackout. In addition to the NERC recommendations, the Task Force made 46 recommendations under the following captions: - institutional issues, - support for and strengthening of ongoing NERC initiatives, - physical and cyber security of North American bulk power systems, and - Canadian nuclear power sector operating procedures. Prompted by the Task Force findings, the MPSC issued an order requiring Michigan utilities and transmission companies to submit a report concerning relay settings on their systems by May 10, 2004. We intend to comply with the MPSC's request. Also, the FERC issued a vegetation management order requiring entities that own, operate, or control designated transmission facilities to report on their vegetation management practices by June 17, 2004. As defined by this particular FERC order, we have a limited amount of designated transmission facilities for reporting purposes pursuant to this order, including a total of six miles of high voltage lines located on or adjacent to some generating plant properties. Few of the recommendations above apply directly to us, since we are not a transmission operator. However, the above recommendations could result in increased transmission costs payable by transmission customers in the future and upgrades to our distribution system. The financial impacts of these recommendations are not quantifiable currently. For additional details and material changes relating to the rate matters and restructuring of the electric utility industry, see Note 2, Uncertainties, "Electric Restructuring Matters," and "Electric Rate Matters." FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new market power screens to assess generation market power and modified measures to mitigate market power where it is found. The screens will apply to all initial market-based rate applications and reviews on an interim basis, which occur every three years. The effects of the modifications are not quantifiable currently. PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The standards relate to restoration after an outage, safety, and customer relations. Financial incentives and penalties are contained within the performance standards. An incentive is possible if all of the established performance standards have been exceeded for a calendar year. However, the performance standards do not contain an approved incentive mechanism; therefore, the value of such an incentive cannot be determined at this point. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. Year-end results for both 2002 and 2003 resulted in compliance with the acceptable level of performance as established by the approved standards. 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 incentive or penalties, if any, on us, nor can we predict the outcome of the appeal. For additional details on performance standards, see Note 2, Uncertainties, "Electric Rate Matters -Performance Standards." CE-25 Consumers Energy Company 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: - abnormal weather, - 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 Michigan Public Service Commission 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. 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: Environmental - potential environmental remediation costs at a number of sites, including sites formerly housing manufactured gas plant facilities. Regulatory - inadequate regulatory response to applications for requested rate increases, and - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, Other - potential rising pension costs due to market losses and lump sum payments as discussed in the "Critical Accounting Policies - Accounting for Pension and OPEB" within this MD&A, - pipeline integrity maintenance and replacement costs, and - pending other litigation. We sell gas to retail customers under tariffs approved by the MPSC. These tariffs measure the gas delivered to customers based on the volume (i.e. mcf) of gas delivered. However, we purchase gas for resale on a Btu basis. The Btu content of the gas available for purchase 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 affect adversely 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. CE-26 Consumers Energy Company In September 2002, the FERC issued an order rejecting our filing to assess certain rates for non-physical gas title tracking services we offered. 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 that stated no refunds are at issue was in error. It directed us to file within 30 days a fair and equitable title-tracking fee and to make refunds to customers with interest based on the difference between the filed fee and the fee paid. We believe that with respect to the FERC jurisdictional transportation, we have not charged any customers title transfer fees, so no refunds will be required. We will make a filing within the 30 days and cannot predict the outcome of this proceeding. 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. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could change the remedial action costs for the sites. For additional details, see Note 2, Uncertainties, "Gas Contingencies - Gas Environmental 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 gas costs; however, the MPSC reviews these costs for prudency in an annual reconciliation proceeding. In January 2004, the MPSC staff and intervenors filed direct testimony in our 2002-2003 GCR case proposing GCR recovery disallowances. In 2003, we reserved $11 million for a settlement agreement associated with the 2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003 through February 2004, at Consumers' authorized rate of return, increased the cost of the settlement by $1 million. The interest was recorded as an expense in 2003. In February 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. For additional details, see Note 2, Uncertainties, "Gas Rate Matters - Gas Cost Recovery." 2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a $156 million annual increase in our gas delivery and transportation rates that included a 13.5 percent return on equity. In September 2003, we filed an update to our gas rate case that lowered the requested revenue increase from $156 million to $139 million and reduced the return on common equity from 13.5 percent to 12.75 percent. The MPSC authorized an interim gas rate increase of $19 million annually. The interim increase is under bond and subject to refund if the final rate relief is a lesser amount. The interim increase order includes a $34 million reduction in book depreciation expense and related income taxes effective only during the period of interim relief. The MPSC order allowed us to increase our rates beginning December 19, 2003. As part of the interim rate order, we agreed to restrict dividend payments to our parent company, CMS Energy, to a maximum of $190 million annually during the period of the interim relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending that the MPSC not rely upon the projected test year data included in our filing and supported by the MPSC Staff and further recommended that the application be dismissed. In response to the Proposal for Decision, the parties have filed exceptions and replies to exceptions. The MPSC is not bound by the ALJ's recommendation and will review the exceptions and replies to exceptions prior to issuing an order on final rate relief. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. This case is not affected by the 2003 gas rate case interim increase order, which reduced book depreciation expense and related income taxes only for the period that we CE-27 Consumers Energy Company receive the interim relief. The original filing was based on December 2000 plant balances and historical data. The December 2003 filing updates the gas depreciation case to include December 2002 plant balances. The proposed depreciation rates, if approved, will result in an annual increase of $12 million in depreciation expense based on December 2002 plant balances. The ALJ's Proposal for Decision is expected in May 2004. 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 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 2003 and expects to file an appeal contesting property taxes for 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund has not been recognized in first quarter 2004 earnings. 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 United States Department of Justice. 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. CE-28 Consumers Energy Company 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. On December 24, 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. In addition, 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 $718 million at March 31, 2004. Property, plant, and equipment serving as collateral for these obligations have a carrying value of $1.471 billion at March 31, 2004. The creditors of these partnerships do not have recourse to the general credit of Consumers. 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, and have not, restated prior periods for the impact of this accounting change. ACCOUNTING STANDARDS NOT YET EFFECTIVE PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, 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 (Act), that was signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy 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. Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No. 106-1 and provides further guidance for accounting for the Act. Proposed FASB Staff Position, No. 106-b states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations (APBO) and postretirement benefit costs should reflect the effects of the Act. As of March 31, 2004, we have not determined whether our postretirement benefit plan is actuarially equivalent to Medicare Part D. Therefore, our measures of APBO and net periodic postretirement benefit CE-29 Consumers Energy Company cost do not reflect any amount associated with the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. If our prescription drug plan is determined to be actuarially equivalent to Medicare Part D, we estimate a decrease in OPEB expense of approximately $20 million for 2004 and a one-time reduction of our benefit obligation of approximately $140 million, to be amortized over future periods. This Proposed FASB Staff Position would be effective for the first interim or annual period beginning after June 15, 2004. STATEMENT OF POSITION, ACCOUNTING FOR CERTAIN COSTS AND ACTIVITIES RELATED TO PROPERTY, PLANT, AND EQUIPMENT: At its September 9, 2003 meeting, the Accounting Standards Executive Committee, of the American Institute of Certified Public Accountants voted to approve the Statement of Position, Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment. The Statement of Position was presented to the FASB for clearance in April 2004. The FASB elected not to clear this proposed Statement of Position. CE-30 CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED MARCH 31 2004 2003 -------- ------- ------- In Millions OPERATING REVENUE $ 1,547 $ 1,442 EARNINGS FROM EQUITY METHOD INVESTEES - 16 OPERATING EXPENSES Operation Fuel for electric generation 154 80 Purchased power - related parties 16 132 Purchased and interchange power 50 82 Cost of gas sold 661 519 Cost of gas sold - related parties 3 25 Other 175 160 ------- ------- 1,059 998 ------- ------- Maintenance 50 52 Depreciation, depletion and amortization 133 116 General taxes 62 59 ------- ------- 1,304 1,225 ------- ------- OPERATING INCOME 243 233 OTHER INCOME (DEDUCTIONS) Accretion expense (1) (2) Other, net 13 (8) ------- ------- 12 (10) ------- ------- INTEREST CHARGES Interest on long-term debt 73 42 Interest on long-term debt - related parties 11 - Other interest 3 5 Capitalized interest (2) (2) ------- ------- 85 45 ------- ------- INCOME BEFORE INCOME TAXES 170 178 INCOME TAXES 59 68 MINORITY INTERESTS 10 - ------- ------- NET INCOME 101 110 PREFERRED SECURITIES DISTRIBUTIONS - 11 ------- ------- NET INCOME AVAILABLE TO COMMON STOCKHOLDER $ 101 $ 99 ======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-31 CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31 2004 2003 -------- ----- ------- In Millions CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 101 $ 110 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization (includes nuclear decommissioning of $1 and $2, respectively) 133 116 Capital lease and other amortization 7 4 Loss on CMS Energy stock - 12 Distributions from related parties less than earnings (16) Changes in assets and liabilities: Increase in accounts receivable and accrued revenue (334) (50) Increase (decrease) in accounts payable (39) 4 Decrease in inventories 337 238 Deferred income taxes and investment tax credit 52 28 Changes in other assets and liabilities 6 (50) ----- ------- Net cash provided by operating activities $ 263 $ 396 ----- ------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excludes assets placed under capital lease) $(110) $ (114) Cost to retire property (18) (18) Restricted cash on hand (a) (1) (1) Investments in Electric Restructuring Implementation Plan (2) (2) Investments in nuclear decommissioning trust funds (1) (2) Proceeds from nuclear decommissioning trust funds 20 6 Cash proceeds from sale of assets - 13 ----- ------- Net cash used in investing activities $(112) $ (118) ----- ------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of long term debt $ - $ 281 Retirement of long-term debt (7) (35) Payment of common stock dividends (78) (78) Preferred securities distributions - (11) Payment of capital lease obligations (3) (3) Decrease in notes payable, net - (205) ----- ------- Net cash used in financing activities $ (88) $ (51) ----- ------- Net Increase in Cash and Cash Equivalents $ 63 $ 227 Cash and Cash Equivalents from Effect of FIN 46R Consolidation 174 - Cash and Cash Equivalents, Beginning of Period 46 244 ----- ------- Cash and Cash Equivalents, End of Period (a) $ 283 $ 471 ===== =======
CE-32 OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
In Millions 2004 2003 ------ ------ CASH TRANSACTIONS Interest paid (net of amounts capitalized) $ 84 $ 61 Income taxes paid - 5 OPEB cash contribution 18 18 NON-CASH TRANSACTIONS Other assets placed under capital lease 1 8 ====== ======
(a) Cash and Cash Equivalents decreased $19 million for the three months ended March 31, 2003 due to reflecting restricted cash as an investing activity rather than classifying as a cash equivalent. THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-33 CONSUMERS ENERGY COMPANY CONSOLIDATED BALANCE SHEETS
MARCH 31 MARCH 31 2004 DECEMBER 31 2003 ASSETS (UNAUDITED) 2003 (UNAUDITED) ----------- ----------- ----------- In Millions PLANT (AT ORIGINAL COST) Electric $ 7,698 $ 7,600 $ 7,356 Gas 2,891 2,875 2,787 Other 2,520 15 21 ----------- ----------- ----------- 13,109 10,490 10,164 Less accumulated depreciation, depletion and amortization 5,504 4,417 4,330 ----------- ----------- ----------- 7,605 6,073 5,834 Construction work-in-progress 392 375 487 ----------- ----------- ----------- 7,997 6,448 6,321 ----------- ----------- ----------- INVESTMENTS Stock of affiliates 21 20 10 First Midland Limited Partnership - 224 259 Midland Cogeneration Venture Limited Partnership - 419 405 Other 18 18 2 ----------- ----------- ----------- 39 681 676 ----------- ----------- ----------- CURRENT ASSETS Cash and cash equivalents at cost, which approximates market 283 46 471 Restricted cash 19 18 19 Accounts receivable, notes receivable and accrued revenue, less allowances of $8, $8 and $5 respectively 626 257 279 Accounts receivable - related parties 12 4 15 Inventories at average cost Gas in underground storage 418 739 256 Materials and supplies 75 70 74 Generating plant fuel stock 41 41 26 Deferred property taxes 161 143 117 Regulatory assets 19 19 19 Derivative instruments 118 14 - Other 68 66 53 ----------- ----------- ----------- 1,840 1,417 1,329 ----------- ----------- ----------- NON-CURRENT ASSETS Regulatory Assets Securitized costs 637 648 678 Postretirement benefits 156 162 180 Abandoned Midland Project 10 10 11 Other 303 266 233 Nuclear decommissioning trust funds 566 575 529 Prepaid pension costs 359 364 - Other 352 174 199 ----------- ----------- ----------- 2,383 2,199 1,830 ----------- ----------- ----------- TOTAL ASSETS $ 12,259 $ 10,745 $ 10,156 =========== =========== ===========
CE-34
MARCH 31 MARCH 31 2004 DECEMBER 31 2003 ----------- ----------- ----------- In Millions STOCKHOLDER'S EQUITY AND LIABILITIES (UNAUDITED) 2003 (UNAUDITED) CAPITALIZATION Common stockholder's equity Common stock, authorized 125.0 shares; outstanding 84.1 shares for all periods $ 841 $ 841 $ 841 Paid-in capital 682 682 682 Accumulated other comprehensive income (loss) 25 17 (175) Retained earnings since December 31, 1992 544 521 535 ----------- ----------- ----------- 2,092 2,061 1,883 Preferred stock 44 44 44 Company-obligated mandatorily redeemable preferred securities of subsidiaries - - 490 Long-term debt 3,572 3,583 2,724 Long-term debt - related parties 506 506 - Non-current portion of capital leases 329 58 121 ----------- ----------- ----------- 6,543 6,252 5,262 ----------- ----------- ----------- MINORITY INTERESTS 682 - - ----------- ----------- ----------- CURRENT LIABILITIES Current portion of long-term debt and capital leases 486 38 290 Notes payable - - 252 Notes payable - related parties 200 200 - Accounts payable 169 200 252 Accrued taxes 175 209 161 Accounts payable - related parties 29 75 88 Current portion of purchase power contract 19 27 26 Deferred income taxes 37 33 29 Other 269 185 198 ----------- ----------- ----------- 1,384 967 1,296 ----------- ----------- ----------- NON-CURRENT LIABILITIES Deferred income taxes 1,281 1,233 961 Regulatory liabilities for cost of removal 1,005 983 937 Postretirement benefits 189 190 566 Regulatory liabilities for income taxes, net 317 312 311 Asset retirement obligations 399 358 364 Other regulatory liabilities 175 172 152 Deferred investment tax credit 84 85 89 Power purchase agreement - MCV Partnership - - 21 Other 200 193 197 ----------- ----------- ----------- 3,650 3,526 3,598 ----------- ----------- ----------- COMMITMENTS AND CONTINGENCIES (Notes 1, 2, and 5) TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES $ 12,259 $ 10,745 $ 10,156 =========== =========== ===========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-35 CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)
THREE MONTHS ENDED MARCH 31 2004 2003 -------- ------ ------ In Millions COMMON STOCK At beginning and end of period (a) $ 841 $ 841 ------ ------ OTHER PAID-IN CAPITAL At beginning and end of period 682 682 ------ ------ ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Minimum Pension Liability At beginning and end of period - (185) ------ ------ Investments At beginning of period 9 1 Unrealized gain on investments (b) 1 - ------ ------ At end of period 10 1 ------ ------ Derivative Instruments At beginning of period 8 5 Unrealized gain on derivative instruments (b) 9 7 Reclassification adjustments included in consolidated net (loss) (b) (2) (3) ------ ------ At end of period 15 9 ------ ------ Total Accumulated Other Comprehensive Income (Loss) 25 (175) ------ ------ RETAINED EARNINGS At beginning of period 521 545 Net Income 101 110 Cash dividends declared - Common Stock (78) (109) Preferred securities distributions - (11) ------ ------ At end of period 544 535 ------ ------ TOTAL COMMON STOCKHOLDER'S EQUITY $2,092 $1,883 ====== ======
CE-36
(UNAUDITED) THREE MONTHS ENDED MARCH 31 2004 2003 ----------- ------ ------ (a)Number of shares of common stock outstanding was 84,108,789 for all periods presented. (b)Disclosure of Comprehensive Income: Investments Unrealized gain on investments, net of tax of $-, and $-, respectively $ 1 $ - Derivative Instruments Unrealized gain on derivative instruments, net of tax $4, and $4, respectively 9 7 Reclassification adjustments included in net income, net of tax benefit $(1), and $(2), respectively (2) (3) Net income 101 110 ------ ------ Total Comprehensive Income $ 109 $ 114 ====== ======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. CE-37 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 is a subsidiary of CMS Energy, a holding company. We are an electric and gas utility company that provides service to customers in Michigan's Lower Peninsula. Our customers include a mix of residential, commercial, and diversified industrial customers. The largest customer segment 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. As of and for the quarter ended March 31, 2004, we determined that the MCV Partnership and the FMLP should be consolidated 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-38 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 March 31, 2004, our restricted cash on hand was $19 million. Restricted cash primarily consists of cash dedicated for repayment of Securitization bonds. It is classified as a current asset as the payments on the related Securitization 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 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 and are excluded from earnings unless such changes in fair value are determined to be other than temporary. Unrealized gains or losses from changes in the fair value of our nuclear decommissioning investments are reported as regulatory liabilities. The fair value of these investments is determined from quoted market prices. Our debt securities are classified as held-to-maturity securities and are reported at cost. 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 March 31, 2004, we have recorded a liability to the DOE for $139 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." 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 and 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. CE-39 Consumers Energy Company 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 the summary of significant accounting policies. 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 and 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. The following table shows our financial information by reportable segment. 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 the variable interest entities the MCV Partnership and the FMLP. We consolidated the MCV Partnership and the FMLP into our consolidated financial statements for the first time as of and for the quarter ended March 31, 2004. For additional details, see Note 7, Implementation of New Accounting Standards.
In Millions -------------------------------------------------------------------- Three Months Ended March 31 2004 2003 --------------------------- ------- ------- Operating revenue Electric $ 631 $ 653 Gas 905 789 Other 11 - ------- ------- Total Operating Revenue $ 1,547 $ 1,442 ======= ======= Net income available to common stockholder Electric $ 45 $ 51 Gas 55 54 Other 1 (6) ------- ------- Total Net Income $ 101 $ 99 ======= =======
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. CE-40 Consumers Energy Company 2: UNCERTAINTIES Several business trends or uncertainties may affect our financial results and condition. These trends or uncertainties have, or we 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 expenses 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 being followed by the MPSC, - recovery of electric restructuring implementation costs, - effects of lost electric supply load to alternative electric suppliers, and - status as an electric transmission customer, instead of an electric transmission owner-operator. Regulatory - effects of potential performance standards payments, - successful implementation of initiatives to reduce exposure to purchased power price increases, - recovery of nuclear decommissioning costs, - responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel, - inadequate regulatory response to applications for requested rate increases, and - response to increases in gas costs, including adverse regulatory response and reduced gas use by customers. Other - pending litigation regarding PURPA qualifying facilities, and - pending other 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 CE-41 Consumers Energy Company 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. 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. Based on his decision with respect to the motion to amend, the judge dismissed certain of plaintiffs' claims without prejudice and denied without prejudice the motions to dismiss other claims. The judge will permit CMS Energy and its other defendants to renew the motions to dismiss at or shortly after the hearing on the motion to amend. CMS Energy, Consumers, and their affiliates 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 are now required to file answers to the amended complaint on or before May 14, 2004. 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: In 1998, the EPA issued regulations requiring the state of Michigan to further limit nitrogen oxide emissions at our coal-fired electric plants. The Michigan Department of Environmental Quality finalized its rules to comply with the EPA regulations in December 2002. The EPA's conditional approval of the Michigan rules was published in April 2004. The Michigan Department of Environmental Quality is currently correcting deficiencies in its rules that were identified by the EPA. If CE-42 Consumers Energy Company the Department of Environmental Quality fails to submit satisfactory revisions to the EPA by the end of May 2004, the EPA's conditional approval will automatically revert to a disapproval, and similar federal regulations will take effect. The EPA and the state regulations require us to make significant capital expenditures estimated to be $771 million. As of March 31, 2004, we have incurred $469 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 2009. These expenditures include installing catalytic reduction technology on 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 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. In addition to modifying the coal-fired electric plants, we expect to purchase nitrogen oxide emissions credits for years 2004 through 2008. The cost of these credits is estimated to average $8 million per year and is accounted for as inventory. The credit inventory is expensed as the coal-fired electric plants generate electricity. The price for nitrogen oxide emissions credits is volatile and could change substantially. The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which requires 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 required to reduce nitrogen oxide emissions 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, through the installation of flue gas desulfurization scrubbers and selective catalytic reduction units. 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. Several bills have been introduced in the United States Congress that would require carbon dioxide emissions reduction. We cannot predict whether any federal mandatory carbon dioxide emissions reduction rules ultimately will be enacted, or the specific requirements of any such rules if they were to become law. To the extent that emissions reduction rules come into legal 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. CE-43 Consumers Energy Company 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. 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 March 31, 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 PSCR plan) 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. 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. We cannot predict the outcome of this matter. ELECTRIC RESTRUCTURING MATTERS ELECTRIC RESTRUCTURING LEGISLATION: 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 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 an annual return of and on capital expenditures in excess of depreciation levels incurred during and before the rate freeze-cap period, - allows for the use of Securitization bonds to refinance qualified costs, CE-44 Consumers Energy Company - 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 jointly expand 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 in order to comply with the Customer Choice Act; for additional details regarding the sale of the transmission facility, see "Transmission Sale" within this section. 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 competitor suppliers. As of April 2004, alternative electric suppliers are providing 823 MW of load. This amount represents 10 percent of the total distribution load and an increase of 50 percent compared to April 2003. ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric restructuring proceedings. They are: - Securitization, - Stranded Costs, - implementation costs, and - transmission. 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. CE-45 Consumers Energy Company 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 2003 true up modified the total Securitization and related tax charges from 1.746 mills per kWh to 1.718 mills per kWh. There will be no impact on customer bills from Securitization for most of our electric customers until the Customer Choice Act cap period expires, and an electric rate case is processed. Securitization charge collections, $13 million for the three months ended March 31, 2004, and $13 million for the three months ended March 31, 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. This amount relates to Clean Air Act expenditures and associated return on those expenditures through December 31, 2002; ROA implementation costs, and previously authorized return on those expenditures through December 31, 2000; and other up front qualified costs related to issuance of the Securitization bonds. In July 2003, we filed for rehearing and clarification on a number of features in the financing order. In December 2003, the MPSC issued its order on rehearing, which rejected our requests for clarification and modification to the dividend payment restriction, failed to rule directly on the accounting clarifications requested, and remanded the proceeding to the ALJ for additional proceedings to address rate design. The ALJ completed hearings in March 2004 and the MPSC decision is not anticipated before May 2004, but could be later. The financing order will become effective after our acceptance of a favorable MPSC order. Bonds will not be issued until resolution of any appeals. Stranded Costs: The Customer Choice Act allows electric utilities to recover their net Stranded Costs, without defining the term. The Act directs the MPSC to establish a method of calculating net Stranded Costs and of conducting related true-up adjustments. 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 transition charge. However, the MPSC has not yet allowed such a transition charge. As a result, we have not recorded regulatory assets to recognize the future recovery of such costs. In 2002 and 2001, the MPSC issued orders finding that we experienced zero net Stranded Costs from 1999 to 2001. The MPSC also declined to resolve numerous issues regarding the net Stranded Cost methodology in a way that would allow a reliable prediction of the level of Stranded Costs for future years. We are currently in the process of appealing these orders with the Michigan Court of Appeals and the Michigan Supreme Court. CE-46 Consumers Energy Company In March 2003, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2002 and for approval of a net Stranded Cost recovery charge. Our net Stranded Costs incurred in 2002, including the cost of money, are estimated to be $47 million with the issuance of Securitization bonds that include Clean Air Act investments, or $104 million without the issuance of Securitization bonds that include Clean Air Act investments. The MPSC scheduled hearings for our 2002 Stranded Cost application to take place during the second quarter of 2004. Once a final financing order on Securitization is reached, we will know the amount of our request for net Stranded Cost recovery for 2002. In February 2004, the MPSC issued an order on Detroit Edison's request for rate relief for costs associated with customers leaving under electric customer choice. The MPSC order allows Detroit Edison to charge a transition surcharge to ROA customers and eliminates Securitization charge offsets. In April 2004, we filed an application with the MPSC seeking approval of net Stranded Costs incurred in 2003, including the cost of money, in the amount of $106 million with the issuance of Securitization bonds that include Clean Air Act investments, or $165 million without the issuance of Securitization bonds that include Clean Air Act investments. Similar to the request that was granted by the MPSC for Detroit Edison, we also requested interim relief for 2002 and 2003 net Stranded Costs. We cannot predict whether the Stranded Cost recovery method adopted by the MPSC will be applied in a manner that will fully offset any associated margin loss from ROA. Implementation Costs: The Customer Choice Act allows electric utilities to recover their implementation costs. The following table outlines the applications filed by us with the MPSC and the status of recovery for these costs.
In Millions ---------------------------------------------------------------------------------- Year Filed Year Incurred Requested Pending Allowed Disallowed ---------- ------------- --------- ------- ------- ----------- 1999 1997 & 1998 $ 20 $ - $ 15 $ 5 2000 1999 30 - 25 5 2001 2000 25 - 20 5 2002 2001 8 - 8 - 2003 & 2004 (a) 2002 7 7 Pending Pending 2004 2003 1 1 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. The MPSC disallowed certain costs, determining that these amounts did not represent costs incremental to costs already reflected in electric rates. In the order received for the year 2001, the MPSC also reserved the right to reevaluate the implementation costs depending upon the progress and success of the ROA program, and ruled that due to the rate freeze imposed by the Customer Choice Act, it was premature to establish a cost recovery method for the allowable implementation costs. In addition to the amounts shown above, we incurred and deferred as a regulatory asset, as of March 31, 2004, $23 million for the cost of money associated with total implementation costs. We believe the implementation costs and associated cost of money are fully recoverable in accordance with the Customer Choice Act. We expect cash recovery from customers to begin after rate cap periods expire. The rate cap expired for large commercial and industrial customers on December 31, 2003. In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision finding that the recovery of 1999 implementation costs is conditional and subject to later disallowance is unlawful. The case was remanded to the MPSC. CE-47 Consumers Energy Company The MPSC issued an order regarding the remanded proceeding that directed us to choose whether we prefer to recover our approved implementation costs through Securitization pursuant to the MPSC's final order in the Securitization proceeding or whether we would prefer to have recovery controlled by the remand proceeding. If the latter option was chosen, the MPSC indicated that it intended to authorize recovery of such implementation costs through the use of surcharges on all customer classes that coincide with the expiration of the Customer Choice Act rate caps. We chose recovery of the approved implementation costs through the use of surcharges and withdrew our request for approved implementation costs recovery from our Securitization proposal. The implementation costs withdrawn from the Securitization case were incurred for the years 1998 through 2000. In the filing we made electing recovery through separate surcharges, we requested approval of surcharges that would allow recovery of implementation costs incurred for the years 1998 through 2001. We requested that the Court of Appeals issue similar remand orders with respect to appeals of the MPSC orders addressing 2000 and 2001 implementation costs. We cannot predict the amounts the MPSC will approve as recoverable costs. Also, we are pursuing authorization at the FERC for the MISO to reimburse us for $8 million in certain electric utility restructuring implementation costs related to our former participation in the development of the Alliance RTO, a portion of which has been expensed. The FERC issued an order denying the MISO's request for authorization to reimburse us and we are in the process of appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. We also requested that the MISO seek authorization to reimburse METC for these development costs. The MISO filed this request but the FERC denied it. While we appeal the FERC's orders, we are also pursuing other potential means of recovery, such as recovery of Alliance RTO development costs at the MPSC. We cannot predict the outcome of the appeal process or the ultimate amount, if any, we will collect for Alliance RTO development costs. Security Costs: The Customer Choice Act allows for recovery of new and enhanced security costs, as a result of federal and state regulatory security requirements. All retail customers, except customers of alternative electric suppliers, would pay these charges. In April 2004, we filed a security cost recovery case with the MPSC for $25 million of cost that regulatory treatment has not yet been granted through other means. The costs are for enhanced security and insurance because of federal and state regulatory security requirements imposed after the September 11, 2001 terrorist attacks. We cannot predict how the MPSC will rule on our requests for the recoverability of security costs. 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 for $290 million to MTH, a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc. The pretax gain was $31 million ($26 million, net of tax). We are currently in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. We cannot predict whether remaining open items will affect materially the recorded gain on the sale. As a result of the sale, after-tax earnings have decreased due to a loss of revenue from wholesale and ROA customers who will buy services directly from MTH. METC has completed the capital program to expand the transmission system's capability to import electricity into Michigan, as required by the Customer Choice Act. We will continue to maintain the system until May 1, 2007 under a contract with METC. Under an agreement with MTH, our transmission rates are fixed by contract at current levels through December 31, 2005, and are subject to the FERC ratemaking thereafter. However, we are subject to certain additional MISO surcharges, which we estimate to be $15 million in 2004. ELECTRIC RATE MATTERS PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. They relate to restoration after an outage, safety, and customer relations. During 2002 and 2003, we monitored and reported to the MPSC our performance relative to the performance standards. Year-end results for both 2002 and 2003 resulted in compliance with the acceptable level of performance as established by the approved standards. Financial incentives and penalties are contained within the performance standards. An incentive is possible if all of the established performance standards have been exceeded for a calendar year. However, the performance standards do not contain an approved incentive mechanism; therefore, the value of such incentive cannot be determined at this point. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. We are a member of an industry coalition that has appealed the customer credit portion of the performance CE-48 Consumers Energy Company standards to the Michigan Court of Appeals. We cannot predict the likely effects of the financial incentive or penalties, if any, on us, nor can we predict the outcome of the appeal. 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 call options and 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 of March 31, 2004, we 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 $19 million for unexpired capacity and energy contracts. On March 31, 2004, we filed a summer assessment for meeting 2004 peak load demand as required by the MPSC, stating that our summer 2004 reserve margin target is 11 percent or supply resources equal to 111 percent of projected summer peak load. Presently, we have a reserve margin of 12 percent, or supply resources equal to 112 percent of projected summer peak load for summer 2004. Of the 112 percent, approximately 103 percent is from owned electric generating plants and long-term contracts, and approximately 9 percent is from short-term contracts. This reserve margin met our summer 2004 reserve margin target. The total premium costs of electricity call options and capacity and energy contracts for 2004 is expected to be approximately $9 million, as of April 30, 2004. As a result of meeting the transmission capability expansion requirements and the market power test, as discussed in 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. We estimate the recovery of increased power supply costs from large commercial and industrial customers to be approximately $30 million in 2004. As allowed under current regulation, we self-implemented the proposed PSCR charge on January 1, 2004. The revenues received from the PSCR charge are also subject to subsequent reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of this filing. 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. Our consolidated retained earnings include undistributed earnings from the MCV Partnership, which at March 31, 2004 are $248 million and at March 31, 2003 are $233 million. The MCV Partnership and the FMLP are variable interest entities and Consumers was determined to be the primary beneficiary. Therefore, we have consolidated the MCV Partnership and the FMLP into our CE-49 Consumers Energy Company consolidated financial statements for the first time as of and for the quarter ended March 31, 2004. For additional details, see Note 7, Implementation of New Accounting Standards. 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 MCV Partnership that capped 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. The remaining liability associated with the loss totaled $19 million at March 31, 2004 and $47 million at March 31, 2003. We expect the PPA liability to be depleted in late 2004. 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. We will expense all cash underrecoveries directly to income once the PPA liability is depleted. 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, we returned to dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in order to maximize recovery 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's Partnership's financial performance and investment in the MCV Partnership is and will be harmed. CE-50 Consumers Energy Company 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, while 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. In February 2004, we filed a resource conservation plan 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 resource conservation plan will reduce the MCV Facility's annual natural gas consumption by an estimated 30 to 40 billion cubic feet. 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 April 2004, the presiding ALJ at the MPSC held a pre-hearing conference regarding the resource conservation plan. The ALJ denied our request to establish a schedule that would have allowed consideration of the plan on an interim basis and established schedule that calls for a Proposal for Decision in September 2004 after which point the MPSC would consider the plan. We cannot predict if or when the MPSC will approve our resource conservation plan. 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 22 years and the MPSC's decision in 2007 or beyond on limiting our recovery of capacity and fixed energy payments. Natural gas prices have been volatile historically. Presently, there is no consensus in the marketplace on the price or range of prices of natural gas in the short term or beyond the next five years. Even with an approved resource conservation plan, 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 of approximately $35 million in taxes CE-51 Consumers Energy Company 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 file 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 2003 and expects to file an appeal contesting property taxes for 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund has not been recognized in first quarter 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. 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 levels of funds provided by the trusts are 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 in "Nuclear Matters" within this section. 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 $25 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, again 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. We plan to file an application with the MPSC seeking approval to increase the surcharge for recovery of decommissioning costs related to Palisades beginning in 2006. We cannot predict how the MPSC will rule on our 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 CE-52 Consumers Energy Company 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 Michigan Department of Environmental Quality continue to find all decommissioning activities at Big Rock are being performed in accordance with applicable regulations including license requirements. Palisades: In March 2004, the NRC completed its end-of-cycle plant performance assessment of Palisades. The assessment for Palisades covered the period from January 1, 2003 through December 31, 2003. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. As of March 2004, all inspection findings were classified as having very low safety significance and all performance indicators indicated performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through September 2005. The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of March 31, 2004, we have loaded 18 dry casks with spent nuclear fuel and are scheduled to load additional dry casks this summer in order to continue operation. 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. A number of utilities have initiated litigation in the United States Court of Claims; we filed our complaint in December 2002. If our litigation against the DOE is successful, we anticipate future recoveries from the DOE. The recoveries will be used 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. The next step will be for the DOE to submit 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. CE-53 Consumers Energy Company 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. 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 2005, and total an estimated $182 million. Our coal transportation contracts expire through 2007, and total an estimated $132 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 unknown at this time, we believe that it will be within the historic 60 to 90 percent range. Power Supply, Capacity, and Transmission: As of March 31, 2004, we had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2004 and 2005 totaling $7 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 $4.581 billion, undiscounted. This amount may vary depending upon plant availability and fuel costs. If a plant was not available to deliver electricity to us, then we would not be obligated to CE-54 Consumers Energy Company make the capacity payment until the plant could deliver. GAS CONTINGENCIES GAS ENVIRONMENTAL MATTERS: We expect to have 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 March 31, 2004, we have recorded a liability of $42 million, net of $39 million of expenditures incurred to date, and a regulatory asset of $67 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. 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 gas costs; however, the MPSC reviews these costs for prudency in an annual reconciliation proceeding. 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 using a roll-in methodology. The roll-in methodology incorporates the GCR under-recovery 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 2003 GCR case. Their positions were that not all of our gas purchasing decisions were prudent during April 2002 through March 2003 and they proposed disallowances. In 2003, we reserved $11 million for a settlement agreement associated with the 2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003 through February 2004, at Consumers' authorized rate of return, increased the cost of the settlement by $1 million. The interest was recorded as an expense in 2003. In February 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. We plan to file a 2003-2004 GCR reconciliation in June 2004. CE-55 Consumers Energy Company In March 2004, the MPSC approved a temporary settlement authorizing us to bill a maximum allowable GCR factor with two quarterly adjustments. The current GCR ceiling factor is $5.94 per mcf, and this is the amount included for May 2004 bills. We are continuing to work with the parties in the case to obtain a final settlement in the 2004-2005 GCR plan case. 2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a $156 million annual increase in our gas delivery and transportation rates that included a 13.5 percent return on equity. In September 2003, we filed an update to our gas rate case that lowered the requested revenue increase from $156 million to $139 million and reduced the return on common equity from 13.5 percent to 12.75 percent. The MPSC authorized an interim gas rate increase of $19 million annually. The interim increase is under bond and subject to refund if the final rate relief is a lesser amount. The interim increase order includes a $34 million reduction in book depreciation expense and related income taxes effective only during the period that we receive the interim relief. The MPSC order allowed us to increase our rates beginning December 19, 2003. As part of the interim order, we agreed to restrict dividend payments to our parent company, CMS Energy, to a maximum of $190 million annually during the period that we receive the interim relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending that the MPSC not rely upon the projected test year data included in our filing and supported by the MPSC Staff and further recommended that the application be dismissed. In response to the Proposal for Decision the parties have filed exceptions and replies to exceptions. The MPSC is not bound by the ALJ's recommendation and will review the exceptions and replies to exceptions prior to issuing an order on final rate relief. 2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. This case is not affected by the 2003 gas rate case interim increase order, which reduced book depreciation expense and related income taxes only for the period that we receive the interim relief. The original filing was based on December 2000 plant balances and historical data. The December 2003 filing updates the gas depreciation case to include December 2002 plant balances. The proposed depreciation rates, if approved, will result in an annual increase of $12 million in depreciation expense based on December 2002 plant balances. The ALJ's Proposal for Decision is expected in May 2004. OTHER UNCERTAINTIES In addition to the matters disclosed in 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 in 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-56 Consumers Energy Company 3: FINANCINGS AND CAPITALIZATION LONG-TERM DEBT: Long-term debt is summarized as follows:
In Millions ------------------------------------------------------------- March 31 December 31 2004 2003 -------- ----------- First mortgage bonds $ 1,483 $ 1,483 Senior notes 1,254 1,254 Bank debt and other 469 469 Securitization bonds 419 426 FMLP debt 411 - -------- ----------- Principal amount outstanding 4,036 3,632 Current amounts (443) (28) Net unamortized discount (21) (21) -------- ----------- Total Long-term debt $ 3,572 $ 3,583 =============================================================
FMLP DEBT: We consolidated the FMLP due to the adoption of Revised FASB Interpretation No. 46. At March 31, 2004, long-term debt of the FMLP, which is consolidated into our financial statements for the first time, consists of:
In Millions ------------------------------------------------------------------------ Maturity 2004 -------- ----------- 11.75% subordinated secured notes 2005 $ 185 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 $ 411 ========================================================================
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. DEBT MATURITIES: At March 31, 2004, the aggregate annual maturities for long-term debt for nine 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 $ 136 $ 559 $ 478 $ 59 $ 504 =====================================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: At March 31, 2004, we had remaining FERC authorization to issue or guarantee up to $500 million of short-term securities and up to $700 million of short-term first mortgage bonds as collateral for such short-term securities. At March 31, 2004, we had remaining FERC authorization to issue up to $740 million of long-term securities for refinancing or refunding purposes, $560 million of long-term securities for general corporate purposes, and $2 billion of long-term first mortgage bonds to be issued solely as collateral for CE-57 Consumers Energy Company other long-term securities. The authorizations expire on June 30, 2004 and we plan to file a renewal application in early May 2004. SHORT-TERM FINANCINGS: At March 31, 2004, we have a $400 million revolving credit facility with banks. $376 million is available for general corporate purposes, working capital, and letters of credit. The MCV Partnership has $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 LEASE OBLIGATIONS: 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. The MCV Partnership classifies this transaction as a capital lease. As of March 31, 2004 capital lease obligations total $372 million, of which $307 million represents the third-party portion of the MCV Facility capital lease. 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 no receivables at March 31, 2004 and we sold $325 million at March 31, 2003. The Consolidated Balance Sheets exclude these amounts from accounts receivable. We continue to service the receivables sold. 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 received from and paid to us under our accounts receivable sales program are shown below:
In Millions ------------------------------------------------------------------------------------------- Three Months Ended March 31 2004 2003 --------------------------- ------- ----------- Proceeds from sales (remittance of collections) under the program $ (297) $ - Collections reinvested under the program $ 1,549 $ 1,375 ======= ===========
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at March 31, 2004, we had $397 million of unrestricted retained earnings available to pay common dividends. Covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. We are also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. In February 2004, we paid $78 million in common stock dividends to CMS Energy. For additional details on the cap on common dividends payable during the current interim gas rate relief period, see Note 2, Uncertainties, "Gas Rate Matters - 2003 Gas Rate Case." CE-58 Consumers Energy Company 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 March 31, 2004:
In Millions ------------------------------------------------------------------------------------------------------------ Issue Expiration Maximum Carrying Recourse Guarantee Description Date Date Obligation Amount Provision (a) --------------------- ------- ---------- ---------- -------- ------------- Standby letters of credit Various Various $ 24 $ - $ - Surety bonds Various Various 8 - - 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 plants Noncompliance with environmental regulations Natural gas transportation Nonperformance Self-insurance requirement Nonperformance Surety bonds Normal operating activity, permits and Nonperformance license Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price Anderson Act for nuclear incident ================================================================================================================================
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 March 31, 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. CE-59 Consumers Energy Company
In Millions --------------------------------------------------------------------------------------------------------- 2004 2003 -------------------------------- ------------------------------- Fair Unrealized Fair Unrealized March 31 Cost Value Gain (Loss) Cost Value Gain (Loss) -------- ------- -------- ----------- ------- ------- ----------- Long-term debt (a) $ 4,015 $ 4,200 $ (185) $ 3,001 $ 3,011 $ (10) Long-term debt - related parties (b) 506 521 (15) - - - Trust Preferred Securities (b) - - - 490 425 65 Available for sale securities: Common stock of CMS Energy (c) 10 21 11 10 10 - SERP 17 22 5 18 18 - Nuclear decommissioning investments (d) 433 566 133 458 529 71 ======= ======== =========== ======= ======= ===========
(a) Includes a principal amount of $443 million at March 31, 2004 and $277 million at March 31, 2003 relating to current maturities. 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 were 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) We recognized a $12 million loss on this investment in 2002 and an additional $12 million loss in the first quarter of 2003 because the loss was other than temporary, as the fair value was below the cost basis for more than six months. As of March 31, 2004, we held 2.4 million shares of CMS Energy Common Stock. (d) On January 1, 2003, we adopted SFAS No. 143 and began classifying our unrealized gains and losses on nuclear decommissioning investments as regulatory liabilities. We previously classified the unrealized gains and losses on these investments in accumulated depreciation. 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, 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, 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. The accounting for changes in the fair value of a derivative (that is, gains or losses) CE-60 Consumers Energy Company 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 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. If an active market develops 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. Derivative accounting is required for certain contracts used to limit our exposure to electricity and gas commodity price risk and interest rate risk. The following table reflects the fair value of all contracts requiring derivative accounting:
In Millions --------------------------------------------------------------------------------------------------------- 2004 2003 March 31 -------------------------------- ------------------------------- ---------------------- Fair Unrealized Fair Unrealized Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss) ---------------------- ------- -------- ----------- ------- ------- ----------- Electric - related contracts $ - $ - $ - $ 8 $ 1 $ (7) Gas contracts 5 11 6 - - - Interest rate risk contracts - - - - (1) (1) Derivative contracts associated with Consumers' investment in the MCV Partnership: Prior to consolidation - - - - 17 17 After consolidation: Gas fuel contracts - 81 81 - - - Gas fuel futures - 50 50 - - - ======= ======== =========== ======= ======= ===========
The fair value of all derivative contracts is included in either Derivative Instruments or Other Assets on the 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 the Consolidated Balance Sheets. CE-61 Consumers Energy Company ELECTRIC CONTRACTS: Our electric utility business uses 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. 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. INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk associated with forecasted interest payments on variable-rate debt. These interest rate swaps are designated as cash flow hedges. As such, we record any change in the fair value of these contracts in accumulated other comprehensive income unless the swaps are sold. As of March 31, 2004, we did not have any interest rate swaps outstanding. As of March 31, 2003, we had entered into a swap to fix the interest rate on $75 million of variable-rate debt. This swap expired in June 2003. We were able to apply the shortcut method to this interest rate hedge; therefore, there was no ineffectiveness associated with this hedge. DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV PARTNERSHIP: Natural 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. The FASB issued Derivatives Implementation Group Issue C-16, which became effective April 1, 2002, regarding natural gas commodity contracts that combine an option component and a forward component. This guidance requires either that the entire contract be accounted for as a derivative or the components of the contract be separated into two discrete contracts. Under the first alternative, the entire contract considered together would not qualify for the normal purchases and sales exception under the revised guidance. Under the second alternative, the newly established forward contract could qualify for the normal purchases and sales exception, while the option contract would be treated as a derivative under SFAS No. 133 with changes in fair value recorded through earnings. At April 1, 2002, the MCV Partnership had nine long-term gas contracts that contained both an option and forward component. As such, they were no longer accounted for under the normal purchases and sales exception and the MCV Partnership began mark-to-market accounting of these nine contracts through earnings. Based on the natural gas prices, at the beginning of April 2002, the MCV Partnership recorded a $58 million gain for the cumulative effect of this accounting change. During the fourth quarter of 2002, the MCV Partnership removed the option component from three of the nine long-term gas contracts, which should reduce some of the earnings volatility. The MCV Partnership expects future earnings volatility on the six remaining long-term gas contracts that contain volume optionality, since changes to this mark-to-market gain will be recorded on a quarterly basis during the remaining life of approximately four years for these gas contracts. From April 2002 to March 2004, the MCV Partnership recorded an additional net mark-to-market gain of $23 million for these gas contracts for a cumulative CE-62 Consumers Energy Company mark-to-market gain through March 31, 2004 of $81 million, which will reverse over the remaining life of these gas contracts, ranging from 2004 to 2007. For the three months ended March 31, 2004, the MCV Partnership recorded in Fuel for Electric Generation a $6 million net mark-to-market gain in earnings associated with these contracts Natural Gas Fuel Futures and Options: 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 and option contracts 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. These financial instruments are derivatives under SFAS No. 133 and the contracts that are used to secure the anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133, since they hedge the price risk associated with the cost of natural gas. 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 resulting mark-to-market gains and losses from cost mitigation activities are flowed through the MCV Partnership's earnings. Cash is deposited with the broker in a margin account at the time futures or options contracts are initiated. The change in market value of these contracts requires adjustment of the margin account balances. The margin account balance as of March 31, 2004 was recorded as a current asset in Other Assets, in the amount of $2 million. For the three months ended March 31, 2004, the MCV Partnership has recognized in other comprehensive income, an unrealized $20 million increase on the futures contracts, which are hedges of forecasted purchases for plant use of market priced gas. This resulted in a net $51 million gain in other comprehensive income as of March 31, 2004. This balance represents natural gas futures with maturities ranging from April 2004 to December 2007, of which $34 million of this gain is expected to be reclassified into earnings within the next twelve months. As of March 31, 2004, Consumers' pretax proportionate share of the MCV Partnership's $51 million net gain recorded in other comprehensive income is $25 million. The MCV Partnership also has recorded, as of March 31, 2004, a $50 million current derivative asset, representing the mark-to-market gain on natural gas futures for anticipated projected electric and steam sales accounted for as hedges. In addition, for the three months ended March 31, 2004, the MCV Partnership has recorded a net $5 million gain in earnings from hedging activities related to natural gas requirements for the MCV Facility operations and a net $1 million gain in earnings from cost mitigation activities. CE-63 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. 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." The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years. We made a contribution of $18 million to our 401(h) and VEBA trust funds in March 2004. We plan to make additional contributions of $53 million in 2004. Costs: The following table recaps the costs incurred in our retirement benefits plans:
In Millions ------------------------------------------------------------------------------------------ Pension OPEB Three Months Ended March 31 2004 2003 2004 2003 --------------------------- ------ ------ ------ ------ Service cost $ 10 $ 10 $ 5 $ 4 Interest expense 18 19 16 15 Expected return on plan assets (27) (20) (11) (10) Amortization of: Net loss 3 2 6 5 Prior service cost 1 2 (2) (1) ------ ------ ------ ------ Net periodic pension and postretirement benefit cost $ 5 $ 13 $ 14 $ 13 ====== ====== ====== ======
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that was signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. We are continuing to defer recognizing the effects of the Act in our 2004 financial statements, as permitted by FASB Staff Position No. 106-b. When accounting guidance is issued, our retiree health benefit obligation may be adjusted. For additional details, see Note 7, Implementation of New Accounting Standards. As of March 31, 2004, we have recorded a prepaid pension asset of $379 million, $20 million of which is in other current assets on our consolidated balance sheets. CE-64 Consumers Energy Company 6: ASSET RETIREMENT OBLIGATIONS SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: 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: - $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 ARO liability would increase by $22 million. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as 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. There is a low probability of a retirement date, so no liability has been recorded for these assets. 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 are based largely on third-party cost estimates. The following tables describe our assets that have legal obligations to be removed at the end of their useful life.
March 31, 2004 In Millions ---------------------------------------------------------------------------------------------------------------------- In Service Trust ARO Description Date Long Lived Assets Fund ----------------------------------------- ---------- ------------------------------------ -------- Palisades - decommission plant site 1972 Palisades nuclear plant $ 497 Big Rock - decommission plant site 1962 Big Rock nuclear plant 69 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 - ======================================================================================================================
CE-65 Consumers Energy Company
March 31, 2004 In Millions ------------------------------------------------------------------------------------------------------------------ ARO Liability ARO ------------------ Cash flow Liability ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 3/31/04 ------------------------------- ------ -------- -------- ------- --------- --------- --------- Palisades - decommission $ 249 $ 268 $ - $ - $ 5 $ 31 $ 304 Big Rock - decommission 61 35 - (21) 3 22 39 JHCampbell intake line - - - - - - - Coal ash disposal areas 51 52 - - 1 - 53 Wells at gas storage fields 2 2 - - - - 2 Indoor gas services relocations 1 1 - - - - 1 ------ -------- -------- ------- --------- --------- --------- Total $ 364 $ 358 $ - $ (21) $ 9 $ 53 $ 399 ====== ======== ======== ======= ========= ========= =========
The Palisades and Big Rock cash flow revisions resulted from new decommissioning reports filed with the MPSC in March 2004. 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 obligations have been accrued through depreciation charges. We estimate that we had $1.005 billion at March 31, 2004 and $937 million at March 31, 2003 of previously accrued asset removal costs related to our regulated operations, for 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. On December 24, 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. In addition, 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 $718 million at March 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of CE-66 Consumers Energy Company $1.471 billion at March 31, 2004. The creditors of these partnerships do not have recourse to the general credit of Consumers. 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, and have not, restated prior periods for the impact of this accounting change. ACCOUNTING STANDARDS NOT YET EFFECTIVE PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, 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 (Act), that was signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy 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. Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No. 106-1 and provides further guidance for accounting for the Act. Proposed FASB Staff Position, No. 106-b states that for plans that are actuarially equivalent to Medicare Part D, employers' measures of accumulated postretirement benefit obligations (APBO) and postretirement benefit costs should reflect the effects of the Act. As of March 31, 2004, we have not determined whether our postretirement benefit plan is actuarially equivalent to Medicare Part D. Therefore, our measures of APBO and net periodic postretirement benefit cost do not reflect any amount associated with the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. If our prescription drug plan is determined to be actuarially equivalent to Medicare Part D, we estimate a decrease in OPEB expense of approximately $20 million for 2004 and a one-time reduction of our benefit obligation of approximately $140 million, to be amortized over future periods. This Proposed FASB Staff Position would be effective for the first interim or annual period beginning after June 15, 2004. CE-67 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. 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 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 CO-1 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. 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. CMS ENERGY 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 at 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 June 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. 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 parties are now awaiting transfer of the file from Wayne County to Jackson County. 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. CO-2 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. Some of the defendants in the MDL matter who are also defendants in the Texas-Ohio case are trying to have the Texas-Ohio case transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case has agreed to extend the time for all defendants to answer or otherwise respond to the complaint until after the MDL panel decides whether to take the case. 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 and are seeking to have it transferred to the MDL proceeding in Nevada. 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. CO-3 However, 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 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 are now required to file answers to the amended complaint on or before May 14, 2004. 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. Based on his decision with respect to the motion to amend, the judge dismissed certain of plaintiffs' claims without prejudice and denied without prejudice the motions to dismiss other claims. The judge will permit CMS Energy and the other defendants to renew the motions to dismiss at or shortly after the hearing on the motion to amend. CMS Energy, Consumers, and their affiliates 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-4 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 first quarter of 2004, CMS Energy filed or furnished the following Current Reports on Form 8-K: - 8-K filed on January 22, 2004 covering matters pursuant to Item 5, Other Events and Item 12, Results of Operations and Financial Condition; - 8-K furnished on March 10, 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); and - 8-K filed on March 18, 2004 covering matters pursuant to Item 5, Other Events. CO-5 CONSUMERS During the first quarter of 2004, Consumers filed or furnished the following Current Reports on Form 8-K: - 8-K filed on January 22, 2004 covering matters pursuant to Item 5, Other Events and Item 12, Results of Operations and Financial Condition; - 8-K furnished on March 10, 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); and - 8-K filed on March 18, 2004 covering matters pursuant to Item 5, Other Events. CO-6 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: May 7, 2004 By: /s/ Thomas J. Webb ------------------------------------- Thomas J. Webb Executive Vice President and Chief Financial Officer CONSUMERS ENERGY COMPANY (Registrant) Dated: May 7, 2004 By: /s/ Thomas J. Webb ------------------------------------- Thomas J. Webb Executive Vice President and Chief Financial Officer CO-7 CMS ENERGY AND CONSUMERS EXHIBITS
EXHIBIT NUMBER 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