ITEM 1. BUSINESS
GENERAL
CMS ENERGY
CMS Energy was formed in Michigan in 1987 and is an energy holding company operating through subsidiaries in the United States and in selected markets around the world. Its two principal subsidiaries are Consumers and Enterprises. Consumers is a public utility that provides natural gas and/or electricity to almost 6 million of Michigan's 10 million residents and serves customers in all 68 of the state's Lower Peninsula counties. Through various subsidiaries, Enterprises is engaged in energy businesses in the United States and in selected international markets.
In 2003, CMS Energy's consolidated operating revenue was approximately $5.5 billion. See BUSINESS SEGMENTS later in this Item 1 for further discussion of each segment.
CONSUMERS
Consumers was formed in Michigan in 1968 and is the successor to a corporation organized in Maine in 1910 that conducted business in Michigan from 1915 to 1968. In 1997, Consumers changed its name from Consumers Power Company to Consumers Energy Company to better reflect its integrated electricity and gas businesses.
Consumers' service areas include automotive, metal, chemical and food products as well as a diversified group of other industries. Consumers' consolidated operations account for a majority of CMS Energy's total assets and income, as well as a substantial portion of its operating revenue. At year-end 2003, Consumers' customer base and operating revenues were as follows:
- ------------------------- (a) Reflects total number of customers, taking into account the approximately 0.6 million combination electric and gas customers that are included in each of the Electric Utility Business and Gas Utility Business numbers above.
Consumers' rates and certain other aspects of its business are subject to the jurisdiction of the MPSC and FERC, as described in CMS ENERGY AND CONSUMERS REGULATION later in this Item 1.
CONSUMERS' PROPERTIES -- GENERAL: Consumers and its subsidiaries own their principal properties in fee, except that most electric lines and gas mains are located in public roads or on land owned by others pursuant to easements and other rights. Almost all of Consumers' properties are subject to the lien of its First Mortgage Bond Indenture. For additional information on Consumers' properties see BUSINESS SEGMENTS -- Consumers' Electric Utility Operations -- Electric Utility Properties, and -- Consumers' Gas Utility Operations -- Gas Utility Properties, below.
BUSINESS SEGMENTS
CMS ENERGY FINANCIAL INFORMATION
For information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to all of CMS Energy's business segments and international and domestic operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION
AND CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS AND NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSUMERS' ELECTRIC UTILITY OPERATIONS
Based on the average number of customers, Consumers' electric utility operations, if independent, would be the thirteenth largest electric utility company in the United States. Consumers' electric utility operations include the generation, purchase, distribution and sale of electricity. At year-end 2003, it served customers in 61 of the 68 counties of Michigan's Lower Peninsula. Principal cities served include Battle Creek, Flint, Grand Rapids, Jackson, Kalamazoo, Midland, Muskegon and Saginaw. Consumers' electric utility customer base includes a mix of residential, commercial and diversified industrial customers, the largest segment of which is the automotive industry. Consumers' electric utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of such customers is not reasonably likely to have a material adverse effect on its financial condition.
Consumers' electric utility operations are seasonal. The summer months usually increase demand for electric energy, principally due to the use of air conditioners and other cooling equipment, thereby affecting revenues. In 2003, Consumers' electric sales were 36 billion kWh and retail open access deliveries were 3 billion kWh, for total electric deliveries of 39 billion kWh. In 2002, Consumers' electric sales were 37 billion kWh and retail open access deliveries were 2 billion kWh, for total electric deliveries of 39 billion kWh.
Consumers' 2003 summer peak demand was 7,721 MW (excluding retail open access loads) and 8,170 MW (including retail open access loads). For the 2002-03 winter period, Consumers' winter peak demand was 5,862 MW (excluding retail open access loads) and 6,140 MW (including retail open access loads). In December 2003, Consumers experienced peak demand of 5,657 MW (excluding retail open access loads) and 6,093 MW (including retail open access loads). Based on its summer 2003 forecast, Consumers carried an 11 percent reserve margin target. However, as a result of lower than forecasted peak loads, Consumers' ultimate reserve margin was 14.7 percent compared to 20.6 percent in 2002. Currently, Consumers has a reserve margin of 5.0 percent, or supply resources equal to 105 percent of projected summer peak load for summer 2004 and is in the process of securing the additional capacity needed to meet its summer 2004 reserve margin target of 11 percent (111 percent of projected summer peak load). The ultimate use of the reserve margin will depend primarily on summer weather conditions, the level of retail open access requirements being served by others during the summer, and any unscheduled plant outages.
ELECTRIC UTILITY PROPERTIES
GENERATION: At December 31, 2003, Consumers' electric generating system consists of the following:
- ------------------------- (a) Represents Consumers' share of the capacity of the J H Campbell 3 unit, net of 6.69 percent (ownership interests of the Michigan Public Power Agency and Wolverine Power Supply Cooperative, Inc.).
(b) Cobb 1-3 are retired coal fired units that were converted to gas fired. Units were placed back into service in the years indicated.
(c) Represents Consumers' share of the capacity of Ludington. Consumers and Detroit Edison have 51 percent and 49 percent undivided ownership, respectively, in the plant.
(d) Represents Consumers' share of net pumped storage generation. This facility electrically pumps water during off-peak hours for storage to later generate electricity during peak-demand hours.
(e) Includes 1,240 MW of purchased contract capacity from the MCV Facility.
In 2003, through long-term purchase contracts, options, spot market and other seasonal purchases, Consumers purchased up to 2,353 MW of net capacity from other power producers (the largest of which was the MCV Partnership), which amounted to 30.5 percent of Consumers' total system requirements.
DISTRIBUTION:
Consumers' distribution system includes:
- 347 miles of high-voltage distribution radial lines operating at 120 kilovolts and above;
- 4,164 miles of high-voltage distribution overhead lines operating at 23 kilovolts and 46 kilovolts;
- 16 subsurface miles of high-voltage distribution underground lines operating at 23 kilovolts and 46 kilovolts;
- 54,922 miles of electric distribution overhead lines;
- 8,526 subsurface miles of underground distribution lines; and
- substations having an aggregate transformer capacity of 20,605,680 kilovoltamperes.
Consumers formerly owned a high-voltage transmission system that interconnects Consumers' electric generating plants at many locations with transmission facilities of unaffiliated systems, including those of other utilities in Michigan and Indiana. The interconnections permit a sharing of the reserve capacity of the connected systems. This allows mutual assistance during emergencies and substantially reduces investment in utility plant facilities. On May 1, 2002, Consumers transferred its investment in the high-voltage transmission system to a third party, Michigan Electric Transmission Company, LLC. Consequently, Consumers no longer owns or controls transmission facilities either directly or indirectly. For additional information on the sale of the
transmission assets, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS -- TRANSMISSION SALE and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- ELECTRIC RESTRUCTURING MATTERS -- TRANSMISSION SALE.
FUEL SUPPLY: Consumers has four generating plant sites that burn coal. These plants constitute 76 percent of Consumers' baseload supply, the capacity used to serve a constant level of customer demand. In 2003, these plants produced a combined total of 20,091 million kWhs of electricity and burned 10.1 million tons of coal. On December 31, 2003, Consumers had on hand a 28-day supply of coal. For additional information on future sources of coal, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- OTHER ELECTRIC UNCERTAINTIES -- COMMITMENTS FOR FUTURE PURCHASES -- COAL SUPPLY.
Consumers owns Palisades, an operating nuclear power plant located near South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers transferred its authority to operate Palisades to the NMC. During 2003, Palisades' net generation was 6,151 million kWhs, constituting 23.3 percent of Consumers' baseload supply. Palisades' nuclear fuel supply responsibilities are under NMC's control as agent for Consumers. New fuel contracts are being written as NMC agreements. Consumers/NMC currently have sufficient contracts for uranium concentrates to provide up to 42 percent of its fuel supply requirements for the fall 2004 reload. A mix of spot and medium-term uranium concentrates contracts are currently being negotiated to provide for the remaining open requirements for the 2004 and 2006 reloads. Consumers/NMC also have contracts for conversion services with quantity flexibility to provide up to 100 percent of the requirements for the 2004 reload and approximately 10 percent of the requirements for the 2006 reload. Contracts to provide for the future Consumers/ NMC requirements are currently being pursued with all suppliers of conversion services. Enrichment services contracts with quantity flexibility ranging up to 100 percent of the requirements for the 2004 and 2006 reloads are in place. NMC is currently negotiating a contract for supply of enrichment services beyond 2006.
NMC also has contracts for nuclear fuel services and for fabrication of nuclear fuel assemblies. The fuel contracts are with major private industrial suppliers of nuclear fuel and related services and with uranium producers, converters and enrichers who participate in the world nuclear fuel marketplace. The fabrication contract is effective for the 2004 reload with options to extend the contract for an additional two reloads in 2006 and 2007.
As shown below, Consumers generates electricity principally from coal and nuclear fuel.
- ------------------------- (a) On June 20, 2001, the Palisades reactor was shut down so technicians could inspect a small steam leak on a control rod drive assembly. The defective components were replaced and the plant returned to service on January 21, 2002.
The cost of all fuels consumed, shown below, fluctuates with the mix of fuel burned.
- ------------------------- (a) Weighted average fuel costs.
The Nuclear Waste Policy Act of 1982 made the federal government responsible for the permanent disposal of spent nuclear fuel and high-level radioactive waste by 1998. The DOE has not arranged for storage facilities and it does not expect to receive spent nuclear fuel for storage in 2004. Palisades currently has spent nuclear fuel that exceeds its temporary on-site storage pool capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved steel and concrete vaults known as "dry casks." For additional information on disposal of nuclear fuel and Consumers' use of dry casks, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES -- NUCLEAR MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- OTHER ELECTRIC UNCERTAINTIES -- NUCLEAR MATTERS.
CONSUMERS' GAS UTILITY OPERATIONS
Based on the average number of customers, Consumers' gas utility operations, if independent, would be the 10th largest gas utility company in the United States. Consumers' gas utility operations purchase, transport, store, distribute and sell natural gas. As of December 31, 2003, it was authorized to provide service in 54 of the 68 counties in Michigan's Lower Peninsula. Principal cities served include Bay City, Flint, Jackson, Kalamazoo, Lansing, Pontiac and Saginaw, as well as the suburban Detroit area, where nearly 900,000 of the gas customers are located. Consumers' gas utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of such customers is not reasonably likely to have a material adverse effect on its financial condition.
Consumers' gas utility operations are seasonal. Consumers injects natural gas into storage during the summer months for use during the winter months when the demand for natural gas is higher. Peak demand usually occurs in the winter due to colder temperatures and the resulting increased demand for heating fuels. In 2003, total deliveries of natural gas sold by Consumers and by other sellers who deliver natural gas to customers (including the MCV Partnership) through Consumers' pipeline and distribution network totaled 388 bcf.
During the winter months of 2002-03, cold weather caused heavy withdrawals from Consumers' gas storage fields. As a result, water and other liquids entered certain of Consumers' pipelines. The existence of water and other liquids in the pipelines could cause pipe corrosion, which in turn may increase future maintenance problems and costs.
GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system consists of:
- 25,551 miles of distribution mains throughout Michigan's Lower Peninsula;
- 1,624 miles of transmission lines throughout Michigan's Lower Peninsula;
- 7 compressor stations with a total of 162,000 installed horsepower; and
- 14 gas storage fields located across Michigan with an aggregate storage capacity of 331 bcf and a working storage capacity of 130 bcf.
GAS SUPPLY: In 2003, Consumers purchased 3 percent of its gas from Michigan producers, 66 percent from United States producers outside Michigan and 22 percent from Canadian producers. Authorized suppliers in the gas customer choice program supplied the remaining 9 percent of gas that Consumers delivered.
Consumers' firm transportation agreements are with ANR Pipeline Company, Great Lakes Gas Transmission, L.P., Trunkline Gas Co. and Panhandle Eastern Pipe Line Company. Consumers uses these agreements to deliver gas to Michigan for ultimate deliveries to market. Consumers' firm transportation and city gate arrangements are capable of delivering over 95 percent of Consumers' total gas supply requirements. As of December 31, 2003, Consumers' portfolio of firm transportation from pipelines to Michigan is as follows:
Consumers purchases the balance of its required gas supply under firm city gate contracts and as needed, interruptible contracts. The amount of interruptible transportation service and its use varies primarily with the price for such service and the availability and price of the spot supplies being purchased and transported. Consumers' use of interruptible transportation is generally in off-peak summer months and after Consumers has fully utilized the services under the firm transportation agreements.
NATURAL GAS TRANSMISSION
CMS Gas Transmission was formed in 1988 and owns, develops and manages domestic and international natural gas facilities. In 2003, CMS Gas Transmission's operating revenue was $22 million.
In 1999, CMS Gas Transmission acquired Panhandle, which was primarily engaged in the interstate transmission and storage of natural gas and also provided LNG terminalling and regasification services. Panhandle operated a large natural gas pipeline network, which provided customers in the Midwest and Southwest with a comprehensive array of transportation services. Panhandle's major customers included 25 utilities located primarily in the United States Midwest market area, which encompassed large portions of Illinois, Indiana, Michigan, Missouri, Ohio and Tennessee.
In February 2003, Panhandle sold its one-third equity interest in Centennial for $40 million to Centennial's two other partners, MAPL and TE Products Pipeline Company, Limited Partnership, through its general partner, TEPPCO.
In March 2003, Panhandle transferred $63 million previously committed to collateralize a letter of credit and its one-third ownership interest in Guardian to CMS Gas Transmission. CMS Gas Transmission sold its interest in Guardian to a subsidiary of WPS Resources Corporation in May 2003. Proceeds from the sale were $26 million and the $63 million of cash collateral was released.
In June 2003, CMS Gas Transmission sold Panhandle to Southern Union Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union Panhandle Corp. purchased all of Panhandle's outstanding capital stock for approximately $582 million in cash and 3 million shares of Southern Union common stock. Southern Union Panhandle Corp. also assumed approximately $1.166 billion in debt. In July 2003, Southern Union declared a five percent common stock dividend resulting in an additional 150,000 shares of common stock
for CMS Gas Transmission. In October 2003, CMS Gas Transmission sold its 3.15 million shares to a private investor for $17.77 per share.
In July 2003, CMS Gas Transmission completed the sale of CMS Field Services to Cantera Natural Gas, Inc. for gross cash proceeds of approximately $113 million, subject to post closing adjustments, and a $50 million face value note of Cantera Natural Gas, Inc. The note is payable to CMS Energy for up to $50 million subject to the financial performance of the Fort Union and Bighorn natural gas gathering systems from 2004 through 2008.
NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of 288 miles of gathering and transmission pipelines located in the state of Michigan, with a daily capacity of 0.95 bcf. At December 31, 2003, CMS Gas Transmission had nominal processing capabilities of approximately 0.33 bcf per day of natural gas in Michigan.
At December 31, 2003, CMS Gas Transmission has ownership interests in the following international pipelines:
- ------------------------- (a) CMS Gas Transmission has a 45 percent interest in a consortium that acquired an 88 percent interest in the pipeline.
Properties of certain CMS Gas Transmission subsidiaries are subject to liens of creditors of the respective subsidiaries.
INDEPENDENT POWER PRODUCTION
CMS Generation was formed in 1986. It invests in, acquires, develops, constructs and operates non-utility power generation plants in the United States and abroad. In 2003, the independent power production business segment's operating revenue, which includes revenues from CMS Generation, CMS Operating, S.A., the MCV Facility and the MCV Partnership, was $204 million.
INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2003, CMS Generation had ownership interests in operating power plants totaling 8,766 gross MW (4,149 net MW). At December 31, 2003, additional plants totaling approximately 1,784 gross MW (420 net MW) were under construction or in advanced stages of development. These plants include the Shuweihat power plant, which is under construction in the United Arab Emirates, and the Saudi Petrochemical Company power plant, which is under advanced development and will be located in the Kingdom of Saudi Arabia. In 2004, CMS Generation plans to complete the restructuring of its operations by narrowing the scope of its existing operations and commitments from four to two regions: the U.S. and the Middle East/North Africa. In addition, it plans to sell designated assets and investments that are under-performing, non-region focused and non-synergistic with other CMS Energy business units.
The following table details CMS Generation's interest in independent power plants as of year-end 2003 (excluding the plants owned by CMS Operating, S.R.L. and CMS Electric and Gas and the MCV facility, discussed further below):
- ------------------------- (a) El Chocon is primarily on a spot market basis, however, it has a high dispatch rate due to low cost.
(b) Atacama is not allowed to sell more than 440 MW to the grid. 100 percent of the 440 MW is under contract.
Through a CMS International Ventures subsidiary called CMS Operating, S.R.L., CMS Enterprises, CMS Gas Transmission and CMS Generation have a 100 percent ownership interest in a 128 MW natural gas power plant and a 92.6 percent ownership interest in a 540 MW natural gas power plant, each in Argentina.
Through CMS Electric and Gas, CMS Enterprises has an 86 percent ownership interest in 287 MW of gas turbine and diesel generating capacity in Venezuela.
CMS Midland owns a 49 percent general partnership interest in the MCV Partnership, which was formed to construct and operate the MCV Facility. The MCV Facility was sold to five owner trusts and leased back to the MCV Partnership. CMS Holdings is a limited partner in the FMLP, which is a beneficiary of one of these trusts. Through FMLP, CMS Holdings has a 35 percent Lessor interest in the MCV Facility. The MCV Facility has a net electrical generating capacity of approximately 1,500 MW.
CMS Generation has ownership interests in certain facilities such as Loy Yang, Jorf Lasfar and El Chocon. The Loy Yang assets are owned in fee, but are subject to the security interests of its lenders. CMS Energy is actively working to sell its interest in the Loy Yang facility. The Jorf Lasfar facility is held pursuant to a right of
possession agreement with the Moroccan state-owned Office National de l'Electricite. The El Chocon facility is held pursuant to a 30-year possession agreement.
For information on capital expenditures, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- CAPITAL RESOURCES AND LIQUIDITY AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 5 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (FINANCINGS AND CAPITALIZATION).
OIL AND GAS EXPLORATION AND PRODUCTION
CMS Energy used to own an oil and gas exploration and production company. In October 2002, CMS Energy completed its exit from the oil and gas exploration and production business.
ENERGY RESOURCE MANAGEMENT
In 2003, CMS ERM moved its headquarters from Houston, Texas to Jackson, Michigan. In February 2004, CMS ERM changed its name from CMS Marketing, Services and Trading Company to CMS Energy Resource Management Company. CMS ERM has reduced its business focus and in the future will concentrate on the purchase and sale of energy commodities in support of CMS Energy's generating facilities. CMS ERM previously provided gas, oil, and electric marketing, risk management and energy management services to industrial, commercial, utility and municipal energy users throughout the United States. In January 2003, CMS ERM closed the sale of a major portion of its wholesale natural gas trading book to Sempra Energy Trading. The cash proceeds were approximately $17 million. In April 2003, CMS ERM sold its wholesale electric power business to Constellation Power Source, Inc. Also in April 2003, CMS ERM sold the federal business of CMS Viron, its energy management service provider, to Pepco Energy Services, Inc. In July 2003, CMS ERM sold CMS Viron's non-federal business to Chevron Energy Solutions Company, a division of Chevron U.S.A. In 2003, CMS ERM marketed approximately 85 bcf of natural gas and 5,314 GWh of electricity and its 2003 operating revenue was $711 million.
INTERNATIONAL ENERGY DISTRIBUTION
In October 2001, CMS Energy discontinued the operations of its international energy distribution business. In 2002, CMS Energy discontinued all new development outside North America, which included closing all non-U.S. development offices. In 2003, CMS Energy reclassified to continuing operations SENECA, which is its energy distribution business in Venezuela, and CPEE, which is its energy distribution business in Brazil, due to its inability to sell these assets.
CMS ENERGY AND CONSUMERS REGULATION
CMS Energy is a public utility holding company that is exempt from registration under PUHCA. CMS Energy, Consumers and their subsidiaries are subject to regulation by various federal, state, local and foreign governmental agencies, including those described below.
MICHIGAN PUBLIC SERVICE COMMISSION
Consumers is subject to the MPSC's jurisdiction, which regulates public utilities in Michigan with respect to retail utility rates, accounting, utility services, certain facilities and various other matters. The MPSC also has rate jurisdiction over several limited liability companies in which CMS Gas Transmission has ownership interests. These companies own, or will own, and operate intrastate gas transmission pipelines.
The Attorney General, ABATE, and the MPSC staff typically intervene in MPSC electric- and gas-related proceedings concerning Consumers. For many years, almost every significant MPSC order affecting Consumers has been appealed. Certain appeals from the MPSC orders are pending in the Court of Appeals.
RATE PROCEEDINGS: In 1996, the MPSC issued an order that established the electric authorized rate of return on common equity at 12.25 percent. In 2002, the MPSC issued an order that established the gas authorized rate of return on common equity at 11.4 percent.
MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the retail electric and gas utility businesses has undergone significant changes. In 2000, the Michigan Legislature enacted the Customer Choice Act. The Customer Choice Act provides that as of January 2002, all electric customers have the choice to buy generation service from an alternative electric supplier. The Customer Choice Act also imposes rate reductions, rate freezes and rate caps. For additional information regarding the Customer Choice Act, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- ELECTRIC RESTRUCTURING MATTERS.
As a result of regulatory changes in the natural gas industry, Consumers transports the natural gas commodity that is sold to some customers by competitors like gas producers, marketers and others. Pursuant to a gas customer choice program that Consumers implemented, as of April 2003 all of Consumers' gas customers are eligible to select an alternative gas commodity supplier. Consumers' current GCR mechanism allows it to recover from its customers all prudently incurred costs to purchase natural gas commodity and transport it to Consumers' facilities. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS' GAS UTILITY RATE MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- GAS RATE MATTERS.
FEDERAL ENERGY REGULATORY COMMISSION
FERC has exercised limited jurisdiction over several independent power plants in which CMS Generation has ownership interests, as well as over CMS ERM. Among other things, FERC jurisdiction relates to the acquisition, operation and disposal of assets and facilities and to the service provided and rates charged. Some of Consumers' gas business is also subject to regulation by FERC, including a blanket transportation tariff pursuant to which Consumers can transport gas in interstate commerce.
FERC also regulates certain aspects of Consumers' electric operations including compliance with FERC accounting rules, wholesale rates, operation of licensed hydro-electric generating plants, transfers of certain facilities, and corporate mergers and issuance of securities. FERC is currently soliciting comments on whether it should exercise jurisdiction over power marketers like CMS ERM, requiring them to follow FERC's uniform system of accounts and seek authorization for issuance of securities and assumption of liabilities. These issues are pending before the agency.
NUCLEAR REGULATORY COMMISSION
Under the Atomic Energy Act of 1954, as amended, and the Energy Reorganization Act of 1974, Consumers is subject to the jurisdiction of the NRC with respect to the design, construction, operation and decommissioning of its nuclear power plants. Consumers is also subject to NRC jurisdiction with respect to certain other uses of nuclear material. These and other matters concerning Consumers' nuclear plants are more fully discussed in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES 1 (CORPORATE STRUCTURE AND ACCOUNTING POLICIES) AND 4 (UNCERTAINTIES) OF CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES 1 (CORPORATE STRUCTURE AND ACCOUNTING POLICIES) AND 2 (UNCERTAINTIES) OF CONSUMERS' CONSOLIDATED FINANCIAL STATEMENTS.
OTHER REGULATION
The Secretary of Energy regulates the importation and exportation of natural gas and has delegated various aspects of this jurisdiction to FERC and the DOE's Office of Fossil Fuels.
Pipelines owned by system companies are subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulates the safety of gas pipelines. Consumers is also subject to the Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum pipelines.
CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE
CMS Energy, Consumers and their subsidiaries are subject to various federal, state and local regulations for environmental quality, including air and water quality, waste management, zoning and other matters.
Consumers has installed and is currently installing modern emission controls at its electric generating plants and has converted and is converting electric generating units to burn cleaner fuels. Consumers expects that the cost of future environmental compliance, especially compliance with clean air laws, will be significant because of EPA regulations regarding nitrogen oxide and particulate-related emissions. These regulations will require Consumers to make significant capital expenditures.
Consumers is in the process of closing older ash disposal areas at two plants. Construction, operation, and closure of a modern solid waste disposal area for ash can be expensive, because of strict federal and state requirements. In order to significantly reduce ash field closure costs, Consumers has worked with others to use bottom ash and fly ash as part of temporary and final cover for ash disposal areas instead of native materials, in cases where such use of bottom ash and fly ash is compatible with environmental standards. To reduce disposal volumes, Consumers sells coal ash for use as a filler for asphalt, for incorporation into concrete products and for other environmentally compatible uses. The EPA has announced its intention to develop new nationwide standards for ash disposal areas. Consumers intends to work through industry groups to help ensure that any such regulations require only the minimum cost necessary to adhere to standards that are consistent with protection of the environment.
Like most electric utilities, Consumers has PCB in some of its electrical equipment. During routine maintenance activities, Consumers identified PCB as a component in certain paint, grout and sealant materials at the Ludington Pumped Storage facility. Consumers removed and replaced part of the PCB material. Consumers has proposed a plan to the EPA to deal with the remaining materials and is waiting for a response from the EPA.
Certain environmental regulations affecting CMS Energy and Consumers include, but are not limited to, the Clean Air Act Amendments of 1990 and Superfund. Superfund can require any individual or entity that may have owned or operated a disposal site, as well as transporters or generators of hazardous substances that were sent to such site, to share in remediation costs for the site.
CMS Energy's and Consumers' current insurance coverage does not extend to certain environmental clean-up costs, such as claims for air pollution, some past PCB contamination and for some long-term storage or disposal of pollutants.
For additional information concerning environmental matters, including estimated capital expenditures to reduce nitrogen oxide related emissions, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- CONSUMERS' ELECTRIC UTILITY CONTINGENCIES and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- ELECTRIC CONTINGENCIES.
CMS ENERGY AND CONSUMERS COMPETITION
ELECTRIC COMPETITION
Consumers' electric utility business experiences actual and potential competition from many sources, both in the wholesale and retail markets, as well as in electric generation, electric delivery and retail services.
In the wholesale electricity markets, Consumers competes with other wholesale suppliers, marketers and brokers. Electric competition in the wholesale markets increased significantly since 1996 due to FERC Order 888. While Consumers is still active in wholesale electricity markets, wholesale for resale transactions by Consumers
generated an immaterial amount of Consumers' 2003 revenues from electric utility operations. Consumers believes future loss of wholesale for resale transactions will be insignificant.
A significant increase in retail electric competition has occurred because of the Customer Choice Act and the availability of retail open access. Price is the principal method of competition for generation services. The Customer Choice Act gives all electric customers the right to buy generation service from an alternative electric supplier. As of March 2004, alternative electric suppliers are providing 735 MW of generation supply to retail open access customers. This represents nine percent of Consumers' total generating load and an increase of approximately 42 percent in generation supply being purchased from alternative electric suppliers by retail open access customers. Consumers has applied for, but has not yet been granted, reimbursement for implementation costs incurred for the Electric Customer Choice program. The MPSC is supposed to adopt a mechanism pursuant to the Customer Choice Act to provide for recovery of stranded costs. In 2000 and 2001, the MPSC determined the stranded cost recovery was zero, contrary to Consumers' position. Consumers continues to work toward the adoption of a stranded cost recovery mechanism that will offset margin loss. Consumers cannot predict the total amount of electric supply load that may be lost to competitor suppliers, whether the stranded cost recovery method adopted by the MPSC will be applied in a manner that will fully offset any associated margin loss, or whether implementation costs will be fully recovered.
In addition to retail electric customer choice, Consumers also has competition or potential competition from:
- the threat of customers relocating outside Consumers' service territory;
- the possibility of municipalities owning or operating competing electric delivery systems;
- customer self-generation; and
- adjacent municipal utilities that extend lines to customers near service territory boundaries.
Consumers addresses this competition by offering special contracts, providing additional non-energy services, and monitoring and enforcing compliance with MPSC and FERC rules.
Consumers offers non-energy revenue services to electric customers, municipalities and other utilities in an effort to offset costs. These services include engineering and consulting, construction of customer-owned distribution facilities, equipment sales (such as transformers), power quality analysis, fiber optic line construction, meter reading and joint construction for phone and cable. Consumers faces competition from many sources, including energy management services companies, other utilities, contractors, and retail merchandisers.
CMS ERM, which is a non-utility electric subsidiary, has modified its focus toward optimization of CMS Energy's independent power production portfolio. CMS Energy's independent power production business segment, another non-utility electric subsidiary, faces competition from generators, marketers and brokers, as well as lower power prices on the wholesale market.
For additional information concerning electric competition, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES.
GAS COMPETITION
Competition has existed for the past decade in various aspects of Consumers' gas utility business, and is likely to increase. Competition traditionally comes from alternate fuels and energy sources, such as propane, oil and electricity.
INSURANCE
CMS Energy and its subsidiaries, including Consumers, maintain insurance coverage similar to comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and exclusions that might not fully compensate CMS Energy for all losses. As CMS Energy renews its policies it is
possible that full insurance coverage may not be obtainable on commercially reasonable terms due to restrictive insurance markets.
EMPLOYEES
CMS ENERGY
As of December 31, 2003, CMS Energy and its subsidiaries, including Consumers, had 8,411 full-time equivalent employees, of whom 8,353 are full-time employees and 58 are full-time equivalent employees associated with the part-time work force. Included in the total are 3,800 employees who are covered by union contracts.
CONSUMERS
As of December 31, 2003, Consumers and its subsidiaries had 7,947 full-time equivalent employees, of whom 7,892 are full-time employees and 55 are full-time equivalent employees associated with the part-time work force. Included in the total are 3,483 full-time operating, maintenance and construction Consumers' employees and 293 full-time and part-time Consumers' call center employees who are represented by the Utility Workers Union of America. Consumers and the Union negotiated a collective bargaining agreement for the operating, maintenance and construction employees that became effective as of June 1, 2000 and will continue in full force and effect until June 1, 2005. Consumers and the Union negotiated a collective bargaining agreement for the call center employees that became effective as of April 1, 2003 and will continue in full force and effect until August 1, 2005.
CMS ENERGY EXECUTIVE OFFICERS
(as of March 1, 2004)
- ------------------------- * From July 1997 until October 1999, Mr. Russell served as Manager -- Electric Customer Operations of Consumers.
** From 1997 to 1999, Mr. Mengebier served as Executive Director of Federal Governmental Affairs for CMS Enterprises.
There are no family relationships among executive officers and directors of CMS Energy.
The present term of office of each of the executive officers extends to the first meeting of the Board of Directors after the next annual election of Directors of CMS Energy (scheduled to be held on May 28, 2004).
CONSUMERS EXECUTIVE OFFICERS
(as of March 1, 2004)
- ------------------------- * From July 1997 until October 1999, Mr. Russell served as Manager -- Electric Customer Operations of Consumers.
** From 1997 to 1999, Mr. Mengebier served as Executive Director of Federal Governmental Affairs for CMS Enterprises.
There are no family relationships among executive officers and directors of Consumers.
The present term of office of each of the executive officers extends to the first meeting of the Board of Directors after the next annual election of Directors of Consumers (scheduled to be held on May 28, 2004).
AVAILABLE INFORMATION
CMS Energy's internet address is http://www.cmsenergy.com. You can access free of charge on our website all of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act. Such reports are available as soon as practical after they are electronically filed with the SEC. Also on our website are our:
- Corporate Governance Principles;
- Code of Conduct (Code of Business Conduct and Ethics);
- Board Committee Charters (including the Audit Committee and the Governance and Nominating Committee)
We will provide this information in print to any shareholder who requests it.
ITEM 2.
ITEM 2. PROPERTIES.
Descriptions of CMS Energy's and Consumers' properties are found in the following sections of Item 1, all of which are incorporated by reference herein:
- BUSINESS -- GENERAL -- Consumers -- Consumers Properties -- General;
- BUSINESS -- BUSINESS SEGMENTS -- Consumers Electric Utility Operations -- Electric Utility Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Consumers Gas Utility Operations -- Gas Utility Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Natural Gas Transmission -- Natural Gas Transmission Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Independent Power Production -- Independent Power Production Properties; and
- BUSINESS -- BUSINESS SEGMENTS -- International Energy Distribution
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
CMS Energy, Consumers and some of their subsidiaries and affiliates are parties to certain routine lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various taxes, and rates and licensing. For additional information regarding various pending administrative and judicial proceedings involving regulatory, operating and environmental matters, see ITEM 1. BUSINESS -- CMS ENERGY AND CONSUMERS REGULATION, both CMS Energy's and Consumers' ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's and Consumers' ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CMS ENERGY
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 the best interest of CMS Energy 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 was 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, CMS Enterprises and APT. Integrum alleges several causes of action against APT, CMS Energy and CMS 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 CMS Enterprises from selling and APT from purchasing the CMS Pipeline Assets and an order of specific performance mandating that CMS Energy, CMS 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. CMS Energy, Consumers or their subsidiaries did not employ the individual when Integrum made the offer to purchase the CMS Pipeline Assets. CMS Energy believes that Integrum's claims are without merit. CMS Energy will vigorously defend itself but cannot predict the outcome of this lawsuit.
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. in July 2003, 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. 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 multi-district court litigation ("MDL") panel decides whether to take the case. There is currently pending in the Nevada federal district court a 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.
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 are likely to seek to remove this action to California federal district court and have it transferred to the MDL proceeding in Nevada.
CMS Energy and its subsidiaries will vigorously defend themselves but cannot predict the outcome of these matters.
SEC INVESTIGATION
The SEC is conducting an investigation regarding round-trip trades at CMS MST. For additional details about this investigation, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNCERTAINTIES) -- SEC and Other Investigations.
CMS ENERGY AND CONSUMERS
EMPLOYMENT RETIREMENT INCOME SECURITY ACT CLASS ACTION 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 trial judge consolidated the two cases that were originally filed in July 2002 in United States District Court for the Eastern District of Michigan, and plaintiffs filed an amended consolidated complaint. 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. CMS Energy and Consumers will vigorously defend themselves 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. CMS Energy, Consumers and their affiliates will vigorously defend themselves but cannot predict the outcome of this litigation.
ENVIRONMENTAL MATTERS
CMS Energy and Consumers, as well as their subsidiaries and affiliates are subject to various federal, state and local laws and regulations relating to the environment. Several of these companies have been named parties to various actions involving environmental issues. Based on their present knowledge and subject to future legal and factual developments, they believe it is unlikely that these actions, individually or in total, will have a material adverse effect on their financial condition or future results of operations. For additional information, see both CMS Energy's and Consumers' ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's and Consumers' ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
CMS ENERGY
During the fourth quarter of 2003, CMS Energy did not submit any matters to a vote of security holders.
CONSUMERS
During the fourth quarter of 2003, Consumers did not submit any matters to a vote of security holders.
PART II
ITEM 5.
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
CMS ENERGY
Market prices for CMS Energy's Common Stock and related security holder matters are contained in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 19 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION), which is incorporated by reference herein. At March 8, 2004, the number of registered shareholders totaled 60,791. Information regarding securities authorized for issuance under equity compensation plans is included in our definitive proxy statement, which is incorporated by reference herein.
Recent Sales of Unregistered Securities: On December 5, 2003, in a private placement to institutional investors pursuant to Rule 144A of the Securities Act of 1933, as amended, CMS Energy issued $250 million of 4.50 percent cumulative convertible preferred stock (par value $0.01 per share)(liquidation preference $50 per share) (the "Preferred Stock"). The Preferred Stock was initially sold to Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities, Inc., Wachovia Capital Markets LLC, and Banc One Capital Markets, Inc., as initial purchasers. CMS Energy received approximately $242 million in proceeds after the initial purchasers' discounts and commissions and offering expenses. Holders of the Preferred Stock may convert their stock into shares of CMS Energy Common Stock under certain circumstances. For each share of Preferred Stock surrendered for conversion, the holder will receive 5.0541 shares of CMS Energy Common Stock, which represents an initial conversion price of $9.893 per share (subject to adjustment in certain events). On or after December 5, 2008, under certain circumstances CMS Energy may have the right to cause the Preferred Stock to be automatically converted into shares of CMS Energy Common Stock at the then applicable conversion price. CMS Energy has agreed to file a shelf registration statement with the SEC by November 5, 2004 relating to the resale of the Preferred Stock and the CMS Energy Common Stock issuable upon conversion thereof.
CONSUMERS
Consumers' common stock is privately held by its parent, CMS Energy, and does not trade in the public market. In January, May, August and November 2003, Consumers paid $77.5 million, $31 million, $53 million and $56.5 million in cash dividends, respectively, on its common stock. In February, May, June, November and December 2002, Consumers paid $55 million, $43 million, $56 million, $52 million and $25 million in cash dividends, respectively, on its common stock. Pursuant to interim gas rate relief ordered by the MPSC, Consumers has agreed to limit dividend payments to CMS Energy to a maximum of $190 million annually during the period in which Consumers receives the interim relief.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
CMS ENERGY
Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S SELECTED FINANCIAL INFORMATION, which is incorporated by reference herein.
CONSUMERS
Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' SELECTED FINANCIAL INFORMATION, which is incorporated by reference herein.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
CMS ENERGY
Management's discussion and analysis of financial condition and results of operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS, which is incorporated by reference herein.
CONSUMERS
Management's discussion and analysis of financial condition and results of operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS, which is incorporated by reference herein.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
CMS ENERGY
Quantitative and Qualitative Disclosures About Market Risk is contained in ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- CRITICAL ACCOUNTING POLICIES -- ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND MARKET RISK INFORMATION, which is incorporated by reference herein.
CONSUMERS
Quantitative and Qualitative Disclosures About Market Risk is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- CRITICAL ACCOUNTING POLICIES -- ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION, which is incorporated by reference herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to Financial Statements:
[CMS ENERGY LOGO]
2003 FINANCIAL STATEMENTS
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CMS ENERGY CORPORATION SELECTED FINANCIAL INFORMATION
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- ------------------------- (a) 1999 earnings per average common share includes allocation of the premium on redemption of Class G Common Stock of $(0.26) per CMS Energy basic share, $(0.25) per CMS Energy diluted share and $3.31 per Class G basic and diluted share.
(b) Effective December 31, 2003, Trust Preferred Securities are classified on the balance sheet as Long term debt -- related parties.
(c) Reflects closing price at the October 25, 1999 exchange date.
(d) Excludes off-system transportation customers.
(e) For additional details, see Note 18, Restatement and Reclassification.
(f) For additional details on the reclassification of non-legal cost-of-removal, see Note 16, Asset Retirement Obligations, "Reclassification of Non-Legal Cost of Removal." Following is the amount of cost of removal reclassified from accumulated depreciation to a regulatory liability by year: $983 million in 2003; $907 million in 2002; $870 million in 2001; $896 million in 2000; and $874 million in 1999.
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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-related 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.
In 2003, we continued to implement our "utility plus" strategy centered around growing a healthy utility in Michigan and optimizing the contribution from key Enterprises assets. We sold over $900 million worth of non-strategic assets, enabling us to reduce debt by $1.1 billion. We have taken advantage of historically low interest rates to extend maturities and refinance our debt at lower cost. We completed over $3 billion of financing and refinancing transactions to resolve short-term liquidity concerns at the start of 2003. In addition to improving our capital structure, we contributed $560 million to our defined benefit pension plan. This should result in lower pension costs in the future.
At the foundation of our financial progress was exceptional operating performance. For the second consecutive year, our Michigan gas utility earned the J.D. Power and Associates award for highest residential customer satisfaction with natural gas services in the Midwest. Independent evaluators, like J.D. Power and Associates recognize value and our regulators do too. The MPSC authorized an annual increase in our gas utility rates of $56 million in late 2002, and an additional interim annualized $19 million rate increase in 2003.
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 March 2004, we lost 735 MW or nine percent of our electric business to these alternative electric suppliers. We expect the loss to grow to over 1,000 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, and we have asked the MPSC to approve it quickly.
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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.
Finally, we are working to resolve outstanding litigation that stemmed from energy trading activities in 2001 and earlier. Doing so will permit us to devote more attention to improving business growth. Our business plan is targeted at predictable earnings growth along with reduction in our debt. We are a full year into our five-year plan to reduce by half the debt of the CMS Energy holding company.
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
Financial statements of prior years and quarterly data for all three periods presented have been restated for the following events:
- International Energy Distribution, which includes SENECA and CPEE, is no longer considered "discontinued operations",
- certain derivative accounting corrections, and
- Loy Yang deferred tax accounting correction.
For additional details on the effect of the restatements, see Note 18, Restatement and Reclassification, and Note 19, Quarterly Financial and Common Stock Information (Unaudited).
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-K 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 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,
- achievement of capital expenditure reductions and cost savings,
- 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, CMS-5
- 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 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,
- 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,
- 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 CONSOLIDATED NET LOSS
Our 2003 net loss was $44 million, an improvement of $606 million from 2002. We are continuing to restructure our business operations, and as our financial plan moves forward, we will maintain our strategy of
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selling under-performing or non-strategic assets in order to reduce our debt, to reduce business risk, and to provide for more predictable future earnings.
2003 COMPARED TO 2002: Our net loss was reduced significantly from:
- absence of $379 million, net of tax, of goodwill write downs recorded in 2002 associated with discontinued operations,
- an improvement of CMS Enterprises' earnings due to:
- decrease of $313 million, net of tax, in asset write downs from planned and completed divestitures,
- lower expropriation and devaluation losses at the Argentine facilities due to the stabilization of the Argentine Peso,
- absence of tax charges recorded in 2002 resulting from the loss of indefinite tax deferral for several international investments, and
- higher revenues and lower interest costs within IPP.
- decrease in corporate interest and other.
However, our progress was slowed by:
- Electric Utility earnings:
- higher electric operating costs resulting from higher pension expense, greater depreciation expense reflecting higher levels of plant in service, and increased amortization expense associated with securitized regulatory assets,
- lower electric deliveries from milder weather during the summer, and
- continuation of switching by commercial and industrial customers to alternative electric suppliers.
- loss of $44 million, after-tax, on the sale of Panhandle,
- employee benefit plans net settlement and curtailment loss of $48 million, after tax, related to a large number of employees retiring and exiting these plans, and
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- cumulative effect of a change of accounting resulting in a charge of $23 million, net of tax, due to energy trading contracts that did not meet the definition of a derivative.
2002 COMPARED TO 2001: Our net loss increased $191 million from:
- after-tax charges in recognition of planned and completed divestitures and reduced asset valuations,
- tax credit write-offs in 2002 at the parent level, and
- restructuring and other costs in 2002.
ELECTRIC UTILITY RESULTS OF OPERATIONS
ELECTRIC DELIVERIES: In 2003, electric revenues decreased, reflecting lower deliveries. Most significantly, sales volumes to commercial and industrial customers were 5.6 percent lower than in 2002, a result of these sectors' continued switching to alternative electric suppliers as allowed by the Customer Choice Act. The decrease in revenue is also the result of reduced deliveries to higher-margin residential customers, from a milder summer's impact on air conditioning usage. Overall, electric deliveries, including transactions with other wholesale marketers and other electric utilities, decreased 0.4 billion kWh or 1.1 percent.
In 2002, electric revenue increased by $41 million from the previous year, despite lower deliveries. This was due primarily to increased deliveries to higher-margin residential customers as a result of a significantly warmer summer's impact on air conditioning usage. Deliveries, including transactions with other wholesale marketers and other electric utilities, decreased 0.3 billion kWh or 0.7 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our recovery of power supply costs was fixed, 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 2003, this difference between power supply-related revenues and actual power supply costs benefited operating income by $26 million more than it had in 2002. This increase is primarily the result of increased intersystem revenues due to higher market prices and sales made from surplus capacity. The efficient operation of our generating plants and lower priced purchased power further decreased power supply costs.
In 2002, as compared to 2001, power supply costs and related revenues increased operating income due primarily to reduced purchased power costs because the Palisades plant returned to service in 2002, following an extended 2001 shutdown.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In 2003, net operating expenses and non-commodity revenue decreased operating income by $80 million versus 2002. This decrease relates to increased pension and other benefit costs of $54 million, a scheduled refueling outage at Palisades, and higher transmission costs. More plant in service increased depreciation costs by $8 million, and $11 million of higher amortization
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expense from securitized assets further contributed to decreased operating income. Slightly offsetting the increased operating expenses were higher non-commodity revenues associated with other income.
In 2002, net operating expenses and non-commodity revenue decreased operating income by $21 million compared with 2001. The decrease primarily related to higher transmission expenses and increased depreciation costs from more plant in service.
ASSET SALES: The reduction in operating income from asset sales for 2003 versus 2002, and the increase in operating income from asset sales for 2002 versus 2001 reflect the $31 million pretax gain associated with the 2002 sale of our electric transmission system and the $7 million pretax gain associated with the 2002 sale of nuclear equipment from the cancelled Midland project.
GENERAL TAXES: In 2003, general taxes decreased from 2002 due primarily to reductions in MSBT expense, resulting primarily from a tax credit received from the State of Michigan associated with construction of the new corporate headquarters on a qualifying Brownfield site. In 2002, general taxes increased over 2001 due to increases in MSBT and property tax accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily to higher average debt levels, but also because of higher average interest rates. In 2002, fixed charges decreased versus 2001 because of a reduction in long-term debt.
INCOME TAXES: In 2003, income tax decreased versus 2002 due primarily to lower earnings by the electric utility. In 2002, income tax expense increased versus 2001 due primarily to increased earnings.
GAS UTILITY RESULTS OF OPERATIONS
GAS DELIVERIES: In 2003, gas deliveries, including miscellaneous transportation, increased 4.1 bcf or 1.1 percent versus 2002. Despite increased system deliveries, gas revenues actually declined by $1 million. Colder weather during the first quarter of 2003 increased deliveries to the residential and commercial sectors. Increased deliveries resulted in a $6 million increase in gas revenues. However, the revenue increase was offset by a $7 million gas loss adjustment recorded as a reduction to gas revenues.
In 2002, gas revenues increased by $21 million from the previous year. System deliveries, including miscellaneous transportation, increased 9.4 bcf or 2.6 percent. The increase was due primarily to colder weather that increased deliveries to the residential and commercial sectors.
GAS RATE INCREASE: In November 2002, the MPSC issued a final gas rate order authorizing a $56 million annual increase to gas tariff rates. As a result of this order, 2003 gas revenues increased $39 million. In 2002, gas rate increases led to increased gas revenues of $25 million over 2001.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: In 2003, gas wholesale and retail services and other gas revenues increased $1 million. The $1 million increase includes primarily the following two items. In 2003, we reversed a $4 million reserve, originally recorded in 2002, for non-physical gas title tracking services.
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In addition, in 2003, we reserved $11 million for the settlement agreement associated with the 2002-2003 GCR disallowance. For additional details regarding both of these issues, see the Gas Utility Business Uncertainties in the "Outlook" section of this MD&A.
OPERATION AND MAINTENANCE: In 2003, operation and maintenance expenses increased versus 2002 due to increases in pension and other benefits costs of $27 million and additional expenditures on safety, reliability, and customer service. In 2002, operation and maintenance expenses increased versus 2001 due to the recognition of gas storage inventory losses and additional expenditures on customer reliability and service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In 2003, the net of general tax expense, depreciation expense, and other income decreased operating income primarily because of increases in depreciation expense from increased plant in service. In 2002, the net of general tax expense, depreciation expense, and other income decreased operating income primarily because of increases in MSBT and property tax expense accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily to higher average debt levels, but also because of higher average interest rates. In 2002 versus 2001, fixed charges decreased due to lower long-term debt levels.
INCOME TAXES: In 2003 versus 2002, income tax expense increased due to reduced income tax expense in 2002. The 2002 reduction was attributable to flow-through accounting on plant, property and equipment as required by past MPSC rulings. In 2002, income tax expense increased versus 2001 due primarily to increased earnings of the gas utility.
ENTERPRISES RESULTS OF OPERATIONS
In 2003, Enterprises had earnings compared to a significant loss in 2002. This year over year improvement resulted from the:
- elimination of $313 million of asset impairments, net of tax, in 2002 for divestitures and reduced asset valuations,
- lower expropriation and devaluation losses at Argentine facilities, and
- elimination of tax charges in 2002 from the loss of indefinite tax deferral for several international investments.
2002 losses increased by $147 million from 2001 resulting from the:
- increased asset impairments for divestitures and reduced asset valuations, and
- discontinuing and selling several businesses.
OTHER RESULTS OF OPERATIONS
CORPORATE INTEREST AND OTHER:
Our 2003 corporate interest and other net expenses decreased $29 million from 2002 primarily due to reduced restructuring costs and reduced taxes, partially offset by increased interest allocation to continuing operations.
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Our 2002 corporate interest and other net expenses increased $89 million from 2001 primarily due to restructuring charges, including the relocation of corporate offices from Dearborn to Jackson, Michigan, and increased taxes resulting from the loss of certain AMT credit carryforwards.
DISCONTINUED OPERATIONS: For the years ended December 31, 2003 and 2002, discontinued operations included Parmelia, and through their respective dates of sale, Panhandle, CMS Viron, CMS Field Services, and Marysville. For additional 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:
- 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 $13.838 billion at December 31, 2003, 60 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
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loss. The impairment loss recognized is the amount by which the carrying amount exceeds the fair value. We estimate the fair market value of the asset utilizing the best information available. This information includes quoted market prices, market prices of similar assets, and discounted future cash flow analyses. An asset considered held-for-sale is recorded at the lower of its carrying amount or fair value, less cost to sell.
We also assess our ability to recover the carrying amounts of our equity method investments. This assessment requires us to determine the fair values of our equity method investments. The determination of fair value is based on valuation methodologies including discounted cash flows and the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. We also consider the existence of CMS Energy guarantees on obligations of the investee or other commitments to provide further financial support. If the fair value is less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded.
Our assessments of fair value using these valuation methodologies represent our best estimates at the time of the reviews and are consistent with our internal planning. The estimates we use can change over time. If fair values were estimated differently, they could have a material impact on the financial statements.
In 2003, we analyzed impairment indicators related to our long-lived assets and equity method investments. Following our analysis, we reduced the carrying amount of our investment in Parmelia, our investment in SENECA, and an equity investment at CMS Generation to reflect their fair values. 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. For additional details on asset sales, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring.
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 contracted 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 availability 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 a regulatory out provision under the MCV Partnership power purchase agreement. This provision obligates us 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 equity, and
- eliminate our underrecoveries for capacity and 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 operations and maintenance expenses. However, the MCV Partnership's costs of
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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 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 our equity interest in the MCV Partnership 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 equity 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 an economic basis depending on 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. We requested that the MPSC provide interim approval while it conducts a full review of the plan. The MPSC has scheduled a prehearing conference with respect to the MCV resource conservation plan for April 2004. We cannot predict if or when the MPSC will approve our request.
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 our recovery of capacity payments. Natural gas prices have been historically volatile. 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. Therefore, we cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our equity interest in the MCV Partnership.
For additional details, see Note 4, Uncertainties, "Other Consumers' Electric Utility 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.
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 7, Financial and Derivative Instruments.
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The types of contracts we typically classify as derivative instruments are interest rate swaps, foreign currency exchange contracts, electric call options, gas fuel options, 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.
Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA, 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 December 31, 2003, we assumed a market-based interest rate of 1 percent (six-month U.S. Treasury rate) and volatility rates ranging between 65 percent and 120 percent to calculate the fair value of our electric and gas call options.
TRADING ACTIVITIES: Our wholesale power and gas trading activities are also accounted for using the criteria 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. We believe that our mathematical models utilize 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 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.
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The following tables provide a summary of the fair value of our energy trading contracts as of December 31, 2003.
- ------------------------- (a) Reflects the removal of contracts that do not qualify as derivatives under SFAS No. 133 as of January 1, 2003. See Note 17, Implementation of New Accounting Standards.
(b) Reflects $60 million decrease for price risk management assets sold and $30 million increase for price risk management assets received related to the sales of the gas and power books.
(c) Reflects changes in price and net increase/(decrease) of forward positions as well as changes to mark-to-market and credit reserves.
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, 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," "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
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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):
- ------------------------- (a) Fair value exposure could only be realized if we repurchased all of our fixed-rate financing.
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. See discussion of these instruments in Note 18, Restatement and Reclassification.
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. The 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. The weather-based gas supply call options, along with the gas supply call and put options, are used to purchase reasonably priced gas supply. Call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Put options give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices.
The commodity price risk sensitivity analysis was not material for the years ending December 31, 2003 and December 31, 2002.
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):
A sensitivity analysis was not performed for the year ended December 31, 2002. There has been a significant change in trading activity in 2003 from the prior year. As noted in "Trading Activities" within this section, the fair value of contracts outstanding has decreased from $81 million at December 31, 2002 to $15 million at December 31, 2003. For further information, see "Trading Activities" within this section.
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
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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 December 31, 2003, we had no foreign exchange hedging contracts outstanding. As of December 31, 2003, the total foreign currency translation adjustment was a net loss of $419 million, which included a net hedging loss of $18 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.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
For additional details on market risk and derivative activities, see Note 7, Financial and Derivative Instruments.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects throughout the world. As a result of a change in business strategy, over the last two years 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 December 31, 2003, cumulative foreign currency translation decreased stockholders' equity by $419 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: At December 31, 2003, the net foreign currency loss due to the exchange rate of the Australian dollar recorded in the Foreign Currency Translation component of stockholders' equity using an exchange rate of 1.335 Australian dollars per U.S. dollars was $95 million. This amount includes an unrealized loss related to our investment in Loy Yang. This unrealized loss, and the impact of certain deferred taxes associated with the Loy Yang investment, will be realized upon sale, full liquidation, or other disposition of our investment in Loy Yang for a total loss of approximately $110 million. In July 2003, we executed a conditional share sale agreement for our investment in Loy Yang. For additional details, see "Outlook -- Enterprises Outlook" section within this MD&A.
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
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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 December 31, 2003, 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 2.94 pesos per U.S. dollar was $264 million. This amount also reflects the effect of recording, at December 31, 2002, U.S. income taxes on temporary differences between the book and tax bases of foreign investments, including the foreign currency translation associated with our Argentine investments that were no longer considered permanent. For additional details, see Note 8, Income Taxes.
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 December 31, 2003, we had $1.105 billion recorded as regulatory assets and $1.467 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 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, CMS-18
- 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:
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.
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.
In August 2003, we made a planned contribution of $210 million to the Pension Plan. In December 2003, we made an additional contribution of $350 million. As a result of these contributions, we reversed the additional minimum liability and the resulting decrease in equity that we charged in 2002. As of December 31, 2003, we have a prepaid pension asset of $408 million recorded on our consolidated balance sheets.
Market-Related Valuation: We determine pension expense based on a market-related valuation of assets, which reduces year-to-year volatility. The market-related valuation recognizes investment gains or losses over a five-year period from the year in which the gains or losses occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.
Due to the unfavorable performance of the equity markets in the past few years, as of December 31, 2003, we had cumulative losses of approximately $239 million that remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses may result in increases in future pension expense in accordance with SFAS No. 87.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003. This Act 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 deferring recognizing the effects of the Act in our 2003 financial statements, as permitted by FASB Staff Position No. 106-1. When accounting guidance is issued, our retiree health benefit obligation may be adjusted.
For additional details on postretirement benefits, see Note 10, Retirement Benefits.
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
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accounting principle. Accretion of $1 million related to the Big Rock and Palisades' profit component included in the estimated cost of removal was expensed for 2003.
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.
Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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, were reclassified as regulatory liabilities in the accompanying consolidated balance sheets.
For additional details on ARO, see Note 16, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and FERC regulate the recovery of costs to decommission our Big Rock and Palisades nuclear plants. They require, and we have established, external trust funds to finance the decommissioning of both plants. Our electric customers pay a surcharge to fund these trusts. 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. Spent fuel storage costs would not be incurred if the DOE took possession of the spent fuel. There is litigation underway to recover these costs.
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 was stopped since it was considered fully funded, subject to further MPSC review. The funds provided by the trusts, additional customer surcharges, and potential
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funds from DOE litigation are all required to cover fully the decommissioning costs, and we currently expect that to happen. 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.
For additional details on nuclear decommissioning, see Note 1, Corporate Structure and Accounting Policies, "Nuclear Plant Decommissioning."
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 have requested advance payment or other forms of assurances, including margin calls, in connection with maintenance of ongoing deliveries of gas and electricity.
At the beginning of 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, in 2003, we executed a financial improvement plan to address these critical liquidity issues.
In January 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. Gross proceeds from asset sales were $939 million in 2003. 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 will continue to monitor our operating expenses and capital expenditures, evaluate market conditions for financing opportunities, and sell assets that are not consistent with our strategy. We do not anticipate paying dividends in the foreseeable future. The Board of Directors may reconsider or revise this policy from time to time 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 December 31, 2003, $733 million consolidated cash was on hand which includes $201 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. In 2003, Consumers paid $218 million in common stock dividends and Enterprises paid $536 million in common stock dividends and other distributions to us. Enterprises' other distributions include a transfer of 1,967,640 shares of CMS Energy Common Stock, valued at $16 million, in the form of a stock dividend. There was no impact on shares outstanding or the consolidated income statement from this distribution.
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SELECTED MEASURES OF LIQUIDITY AND CAPITAL RESOURCES:
Working capital in 2003 was primarily driven by the following:
- cash proceeds from long-term debt issuance -- $2.080 billion,
- cash proceeds from asset sales -- $939 million, and
- cash proceeds from preferred stock issuance/sale -- $272 million.
partially offset by:
- cash used for long-term debt retirements, excluding current portion -- $1.531 billion,
- cash used for pension contributions -- $560 million, and
- cash used for purchase of property, plant and equipment -- $535 million.
SUMMARY OF CASH FLOWS:
OPERATING ACTIVITIES:
2003: Net cash used in operating activities was $251 million in 2003 compared to net cash provided by operating activities of $614 million in 2002. The change of $865 million was primarily due to an increase in pension plan contributions of $496 million, an increase in inventories of $428 million due to higher gas purchases at higher prices by our gas utility operations, and a decrease in accounts payable and accrued expenses of $232 million due primarily to the sale of CMS MST's wholesale gas and power contracts. This change was partially offset by a decrease in accounts receivable and accrued revenue of $101 million due primarily to the sale of CMS MST's wholesale gas and power contracts.
2002: Net cash provided by operating activities increased $242 million in 2002 primarily due to a decrease in inventories of $479 million due to a lower volume of gas purchased at lower prices, combined with increased sales volumes at higher prices at our gas utility. This increase was partially offset by a smaller decrease in accounts receivable and accrued revenues of $238 million.
INVESTING ACTIVITIES:
2003: Net cash provided by investing activities decreased $626 million in 2003 due primarily to a decrease in asset sale proceeds of $720 million, primarily from the sale of Equatorial Guinea, Powder River, and CMS Oil and Gas in 2002, offset by a decrease in 2003 versus 2002 capital expenditures of $212 million as a result of our strategic plan to reduce capital expenditures.
2002: Net cash provided by investing activities increased $2.178 billion in 2002 due primarily to a decrease in capital expenditures of $492 million as a result of our strategic plan to reduce capital expenditures, and an
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increase in asset sale proceeds of $1.525 billion, resulting primarily from the sales of Equatorial Guinea, Powder River, and CMS Oil and Gas.
FINANCING ACTIVITIES:
2003: Net cash provided by financing activities increased $1.453 billion in 2003 due primarily to an increase in net proceeds from borrowings of $988 million and net proceeds from preferred securities issuances/ sale of $272 million. For additional details on long-term debt activity, see Note 5, Financings and Capitalization.
2002: Net cash used in financing activities increased $2.190 billion in 2002 due primarily to a decrease in net proceeds from borrowings of $1.733 billion and a decrease in net proceeds from common stock and preferred securities of $454 million.
OBLIGATIONS AND COMMITMENTS
The following information on our contractual obligations, off-balance sheet arrangements, and commercial commitments is provided to collect information in a single location so that a picture of liquidity and capital resources is readily available. For additional information on our obligations and commitments see Note 5, Financings and Capitalization.
- ------------------------- (a) This excludes purchase obligations that Consumers has with Genesee, Grayling, and Filer City generating plants because these entities are consolidated under FASB Interpretation No. 46. Purchase obligations related to the MCV Facility PPA assume that the regulatory out provision is exercised in 2007. For additional details, see Note 4, Uncertainties, "Other Consumers' Electric Utility Uncertainties -- The Midland Cogeneration Venture."
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers must obtain FERC authority to issue short and long-term securities. For additional details of Consumers' existing authority, see Note 5, Financings and Capitalization.
LONG-TERM DEBT: Details on long-term debt and preferred securities issuances, retirements, and outstanding balances are presented in Note 5, Financings and Capitalization.
SHORT-TERM FINANCINGS: CMS Energy has $190 million available and Consumers has $390 million available under revolving credit facilities. At December 31, 2003, the lines are available for general corporate purposes, working capital, and letters of credit. Additional details are in Note 5, Financings and Capitalization.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of leased service vehicles and office furniture. The full obligation of our leases could become due in the event of lease payment default. CMS-23
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,
- 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.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we currently sell up to $325 million of certain accounts receivable. For additional details, see Note 5, 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 including the MCV Facility. These contracts require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $43 million per month during 2004, including $34 million related to the MCV Facility. 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 4, Uncertainties, "Consumers' Electric Utility Rate Matters -- Power Supply Costs," and "Other Consumers' Electric Utility Uncertainties -- The Midland Cogeneration Venture."
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.
- ------------------------- (a) At December 31, 2003, we had $175 million of cash collateralized letters of credit and the cash used to collateralize the letters of credit is included in Restricted Cash on the Consolidated Balance Sheets.
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DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at December 31, 2003, Consumers had $373 million of unrestricted retained earnings available to pay common dividends. However, covenants in Consumers debt facilities cap common stock dividend payments at $300 million in a calendar year. Through December 31, 2003, we received the following common stock dividend payments from Consumers:
As of December 18, 2003, Consumers is also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. Because all of the $218 million of common stock dividends to CMS energy were paid prior to December 18, 2003, Consumers was not out of compliance with this new restriction for 2003. In February 2004, Consumers paid a $78 million common stock dividend.
For additional details on the potential cap on common dividends payable included in the MPSC Securitization order see Note 4, Uncertainties, "Consumers' Electric Utility Rate Matters -- Securitization." Also, for additional details on the cap on common dividends payable during the current interim gas rate relief period, see Note 4, Uncertainties, "Consumers' Gas Utility Rate Matters -- 2003 Gas Rate Case."
CAPITAL EXPENDITURES
We estimate the following capital expenditures, including new lease commitments, by expenditure type and by business segments during 2004 through 2006. We prepare these estimates for planning purposes and may revise them.
- ------------------------- (a) These amounts include an attributed portion of Consumers' anticipated capital expenditures for plant and equipment common to both the electric and gas utility businesses.
(b) These amounts include estimates for capital expenditures that may be required by recent revisions to the Clean Air Act's national air quality standards.
OUTLOOK
CORPORATE OUTLOOK
During 2003, we continued to implement a back-to-basics 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 back-to-basics strategy, we are pursuing actively the sale of non-strategic and under-performing assets and have received $3.6 billion of cash from asset sales, securitization proceeds and proceeds from LNG monetization since 2001. For additional details, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. Some of these assets are recorded at estimates of their current fair value. Upon the sale 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
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make any assurance that, these sales will occur. We anticipate that the sales, if any, will result in additional cash proceeds that will be used to retire existing debt.
As we continue to implement our back-to-basics strategy and further reduce our ownership of non-utility assets, the percentage of our future earnings relating to Jorf Lasfar and the MCV Partnership may increase and our total future earnings may depend more significantly upon the performance of Jorf Lasfar and the MCV Partnership. For the year ended December 31, 2003, earnings from our equity method investment in Jorf Lasfar were $61 million and earnings from our equity method investment in the MCV Partnership were $29 million.
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.
For 2003, our electric deliveries, including delivery to customers who chose to buy generation service from an alternative electric supplier, declined 1.4 percent from 2002. This was due to a combination of warmer than normal summer weather in 2002, cooler than normal summer weather in 2003, and a decline in manufacturing activity during 2003. In 2004, we project electric deliveries to grow more than three percent. This short-term outlook for 2004 assumes higher levels of manufacturing activity than in 2003 and normal weather conditions throughout 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.
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,
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- effects of potential performance standards payments, and
- responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
- potential rising pension costs due to market losses and lump sum payments. For additional details, see "Accounting for Pension and OPEB" section within this MD&A.
- pending litigation and government investigations.
For additional details about these trends or uncertainties, see Note 4, 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 8.1 percent. As of December 31, 2003, we have incurred $446 million in capital expenditures to comply with these regulations and anticipate that the remaining $325 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.
Future clean air regulations requiring emission controls for sulfur dioxide, nitrogen oxides, mercury, and nickel may require additional capital expenditures. Total expenditures will depend upon the final makeup of the new regulations.
The EPA continues to make new rules. The EPA has proposed changes to the rules that govern generating plant cooling water intake systems. The proposed rules are scheduled to be final in the first quarter of 2004. We are studying the proposed rules to determine the most cost-effective solutions for compliance.
For additional details on electric environmental matters, see Note 4, 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
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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 March 2004, alternative electric suppliers are providing 735 MW of generation supply to ROA customers. This amount represents nine percent of our distribution load and an increase of 42 percent compared to March 2003. We anticipate this upward trend to continue and expect over 1,000 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 charge a transition surcharge of approximately 0.4 cent per kWh to ROA customers and eliminates securitization offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh for secondary service customers. We are seeking similar recovery of Stranded Costs due to ROA customers leaving our system and are encouraged by this ruling. This ruling may change significantly the anticipated number of customers who choose ROA.
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 financing order will become effective after acceptance by us and 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 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 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 are estimated to be $38 million with the issuance of Securitization bonds that include Clean Air Act investments, or $85 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. We cannot predict how the MPSC will rule on our request 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 has reviewed and allowed certain of the implementation costs incurred through 2001, but has not authorized recovery. Depending upon the outcome of the remanded Securitization proceeding, a significant portion of the implementation costs could be recovered through the Securitization process.
Our application for $2 million of implementation costs in 2002 is currently pending approval by the MPSC. We deferred these costs as a regulatory asset. In addition to the implementation costs filed with the MPSC, as of December 31, 2003, we recorded an additional $2 million for total implementation costs of $91 million. Included in total implementation costs is $19 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 the rate cap period has expired. For additional information on
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rate caps, see "Rate Caps" within this section. Once a final financing order by the MPSC on Securitization is issued, the recoverability of the implementation costs requested will be known. We cannot predict the amounts the MPSC will approve as allowable costs.
Also, we are pursuing authorization at the FERC for 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 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. In addition, we continue to pursue other potential means of recovery with FERC. We cannot predict the outcome of the appeal process or the ultimate amount, if any, the FERC will allow us to collect for implementation 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:
- a rate freeze effective through December 31, 2003, and
- rate caps effective through December 31, 2004 for small commercial and industrial customers, and 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 needed 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: Prior to 1998, the PSCR process provided for the reconciliation of actual power supply costs with power supply revenues. This process assured 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 1998, as part of the electric restructuring efforts, the MPSC suspended the PSCR process, effective through 2001. As a result of the rate freeze imposed by the Customer Choice Act, frozen rates remained in effect until December 31, 2003, and the PSCR process remained suspended. Therefore, changes in power supply costs due to fluctuating electricity prices were not reflected in rates charged to our customers during the rate freeze period.
As a result of meeting the transmission capability expansion requirements and the market power test, we have met the requirements under the Customer Choice Act to return to the PSCR process. For additional details see Note 4, Uncertainties, "Consumers' Electric Utility Restructuring Matters -- Electric Restructuring Legislation."
Accordingly, 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 cap, 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. We continued to collect the equivalent to the Big Rock nuclear decommissioning surcharge consistent with the Customer Choice Act rate freeze in effect through December 31, 2003. Collection of the surcharge stopped, effective January 1, 2004, when the electric rate freeze expired. As a result, our electric revenues will be reduced by $35 million in 2004. However, we expect a portion of this reduction to be offset with increased electric revenues from returning to the PSCR process.
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 CMS-29
restructured, the majority of these contracts are in effect through 2005. As of December 31, 2003, contracts for 301 MW of load have terminated. Of the contracts that have terminated, contracts for 64 MW have gone to an alternative electric supplier and contracts for 237 MW 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. Other new special contracts for 101 MW received interim approval from the MPSC and are awaiting final approval. All new special contracts end by January 1, 2006. We cannot predict the ultimate financial impact of changes related to these power supply contracts, or whether additional special contracts will be necessary or advisable.
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 impact 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 significantly affect:
- 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 currently quantifiable. 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.
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. Approximately 100,000 of our 1.7 million electric customers were without power for approximately 24 hours as a result of the disturbance. We incurred $1 million of immediate expense as a result of the blackout. We continue to cooperate with investigations of the blackout by several federal and state agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC report found no evidence to suggest that the events in Michigan, or actions taken by the Michigan utilities or transmission operators, were factors contributing to the cause of the blackout. Also in November 2003, the United States and Canadian power system outage taskforce preliminarily reported that the primary cause of the blackout was due to transmission line contact with trees in areas outside of Consumers' operating territory. In December 2003, the MPSC issued an order requiring Consumers to report by April 1, 2004, the status of lines used to serve our customers, including details of vegetation trimming practices in calendar year 2003. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations to improve electric transmission reliability. The key recommendations are as follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is not, to submit annual reports on vegetation management beginning March 2005 and improve technology over various milestones throughout 2004. These recommendations could result in increased transmission costs payable by transmission customers in the future. The financial impacts of these recommendations are not currently quantifiable.
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For additional details and material changes relating to the rate matters and restructuring of the electric utility industry, see Note 4, Uncertainties, "Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric Utility Rate Matters."
PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The performance standards establish standards related 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 value of such incentive cannot be determined at this point as the performance standards do not contain an approved incentive mechanism. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. We cannot predict the likely effects of the financial incentive or penalties, if any, on us.
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.
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 cost at a number of sites, including sites formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate increases,
- potential adverse appliance service plan ruling or related legislation, 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 "Accounting for Pension and OPEB" section within this MD&A, and
- pending litigation and government investigations.
Consumers sells 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, Consumers purchases gas for resale on a Btu basis. The Btu content of the gas available for purchase has increased and may result in customers using less gas for the same heating requirement. Consumers fully recovers what it spends to purchase the gas through the approved GCR. However, since the customer is using less gas on a volumetric basis, the revenue from
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the distribution charge (the non-gas cost portion of the customer bill) would be reduced. This could affect adversely Consumers' earnings from it gas utility. The amount of the earnings loss 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 FERC for clarification or rehearing of FERC's December 2003 order. We cannot predict the outcome of this filing.
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 4, 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 February 2004, the parties in the case reached a tentative settlement agreement that would result in a GCR disallowance of $11 million for the GCR period plus $1 million accrued interest through February 2004. A reserve was recorded in December 2003. For additional details, see Note 4, 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 that we receive the 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 its dividend payments to CMS Energy, to a maximum of $190 million annually during the period that Consumers receives 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. The MPSC is not bound by these recommendations and will consider the issues anew after receipt of exceptions and replies to the exception filed by the parties in response to the Proposal for Decision.
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 independent of the 2003 gas rate case. 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.
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,
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- 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 are in the process of filing 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.
The Michigan House of Representatives is scheduled to review the proposed legislation in 2004 that would allow us to remain in the appliance service business. In the interim, the legislature passed a bill to extend to July 1, 2004, the deadline for exiting this business. The full impact of the new code of conduct on our business will remain uncertain until the final judicial resolution of our appeal or the Michigan legislature enacts clarifying legislation.
OTHER CONSUMERS' MATTERS
2001 GAS RATE CASE: In June 2001, we filed an application with the MPSC for a distribution service rate increase. In November 2002, the MPSC approved a $56 million annual distribution service rate increase, with an 11.4 percent authorized return on equity.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our IPP business by narrowing the focus of our existing operations and commitments to North America and the Middle East/North Africa. Accordingly, 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 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 its business risk and outstanding credit guarantees. Our future activities will be centered around meeting contractual obligations, as well as purchasing fuel for and marketing the merchant power from DIG, Michigan Power, LLC, and other IPPs as their current power purchase agreements expire.
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 financial plan,
- changes in exchange rates or local economic 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, and
- impact of ratings downgrades on our liquidity, operating costs, and cost of capital. CMS-33
PENDING ASSET SALE: Affiliates of CMS Generation and CMS Gas Transmission own a 49.6 percent interest in the Loy Yang Power Partnership ("LYPP"), which owns the 2,000 MW Loy Yang coal-fired power project in Victoria, Australia. Due to unfavorable power prices in the Australian market, the LYPP is not generating cash flow sufficient to meet its debt-service obligations. LYPP has A$500 million of term bank debt that, pursuant to extensions from the lenders, is scheduled to mature on March 31, 2004. The partners in LYPP (including affiliates of CMS Generation, CMS Gas Transmission, NRG Energy Inc. and Horizon Energy Australia Investments) have been exploring the possible sale of the project (or control of the project) and a restructuring of the finances of LYPP.
In July 2003, a conditional share sale agreement was executed by the LYPP partners and partners of the Great Energy Alliance Corporation ("GEAC") to sell the project to GEAC for A$3.5 billion ($2.8 billion in U.S. dollars), including A$165 million for the project equity. The partners in GEAC are the Australian Gas Light Company, the Tokyo Electric Power Company, and a group of financial investors led by the Commonwealth Bank of Australia. A recent resolution of an Australian Competition and Consumer Commission objection to the sale has led to an extension of the exclusive arrangement with GEAC to allow enough time to complete the sale. The conditions to completion of the sale to GEAC include consents from LYPP's lenders to a restructuring of the debt and rulings on tax and stamp duty obligations. The project equity portion of the sale price has been reduced to A$155 million ($122 million in U.S. dollars) as a result of working capital and other adjustments, and closing is targeted for March 2004. The share sale agreement and subsequent extensions provide GEAC a period of exclusivity while the conditions of the purchase are satisfied. The ultimate net proceeds to CMS Energy for its equity share in LYPP may be subject to a reduction based on the ultimate resolution of many of the factors described above as conditions to completion of the sale, as well as closing adjustments and transaction costs, and could likely range between $20 million and a nominal amount.
We cannot predict whether this sale to GEAC will be consummated or, if not, whether any of the other initiatives will be successful, and it is possible that CMS Generation may lose all or a substantial part of its remaining equity investment in the LYPP. We previously have written off our equity investment in the LYPP, and further write-offs would be limited to cumulative net foreign currency translation losses. The amount of such cumulative net foreign currency translation losses is approximately $110 million at December 31, 2003. Any such write-off would flow through our income statement but would not result in a reduction in shareholders' equity or cause us to be in noncompliance with our financing agreements.
OTHER OUTLOOK
LITIGATION AND REGULATORY INVESTIGATIONS: We are the subject of various investigations as a result of round-trip trading transactions by CMS MST, including investigations by the United States Department of Justice and the SEC. Additionally, we are a party to 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 4, Uncertainties.
OTHER MATTERS
CONTROL WEAKNESSES AT CMS MST
In late 2001 and during 2002, we identified a number of deficiencies in CMS MST's systems of internal accounting controls. The internal control deficiencies related to, among other things, a lack of account reconciliations, unidentified differences between subsidiary ledgers and the general ledger, and procedures and processes surrounding our accounting for energy trading contracts, including mark-to-market accounting.
Senior management, the Audit Committee of the Board of Directors, the Board of Directors, and the independent auditors were notified of these deficiencies as they were discovered, and we commenced a plan of remediation that included replacing certain key personnel and deploying additional internal and external accounting personnel to CMS MST. While a number of these control improvements and changes were implemented in late 2002, the most important ones occurred in the first quarter of 2003.
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We believe that the improvements to our system of internal accounting controls were appropriate and responsive to the internal control deficiencies that were identified. We monitored the operation of the improved internal controls throughout 2003 and have concluded that they were effective.
NEW ACCOUNTING STANDARDS
See Note 17, Implementation of New Accounting Standards, for discussion of new standards.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: 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 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 provides an implementation deferral until the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the first quarter of 2004 for all entities other than special purpose entities. Special purpose entities must apply either FASB Interpretation No. 46 or Revised FASB Interpretation No. 46 for the first reporting period that ends after December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have adopted Revised FASB Interpretation No. 46 for all entities other than the MCV Partnership and FMLP. We continue to evaluate and gather information regarding those entities. We will adopt the provisions of Revised FASB Interpretation No. 46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest in the MCV Partnership and FMLP, we would consolidate their assets, liabilities, and activities, including $700 million of non-recourse debt, into our financial statements. Financial covenants under our financing agreements could be impacted negatively after such a consolidation. As a result, it may become necessary to seek amendments to the relevant financing agreements to modify the terms of certain of these covenants to remove the effect of this consolidation, or to refinance the relevant debt. As of December 31, 2003, our investment in the MCV Partnership was $419 million and our investment in the FMLP was $224 million.
We determined that we have the controlling financial interest in three entities that are determined to be variable interest entities. We have 50 percent partnership interest in T.E.S Filer City Station Limited Partnership, Grayling Generating Station Limited Partnership, and 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 provide us with the controlling financial interest as defined by the Interpretation. Therefore, we have consolidated these partnerships into our consolidated financial statements for the first time as of December 31, 2003. At December 31, 2003, total assets consolidated for these entities are $227 million and total liabilities are $164 million, including $128 million of non-recourse debt. At December 31, 2003, CMS Energy has outstanding letters of credit and guarantees of $5 million relating to these entities. At December 31, 2003, minority interest recorded for these entities totaled $36 million.
We also determined that we do not hold the controlling financial interest in 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 have reflected $684 million of long-term debt -- related parties and have 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.
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Additionally, we have non-controlling interests in four other variable interest entities. FASB Interpretation No. 46 requires us to disclose certain information about these entities. The chart below details our involvement in these entities at December 31, 2003:
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(a) At December 31, 2003, we recorded 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 $27 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 $59 million, Loy Yang currency translation losses of $110 million, net of tax, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $146 million. Included in the $146 million is 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.
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 is expected to be presented for FASB clearance in 2004 and would be applicable for fiscal years beginning after December 15, 2004. An asset classified as property, plant, and equipment often comprises multiple parts and costs. A component accounting policy determines the level at which those parts are recorded. Capitalization of certain costs related to property, plant, and equipment are included in the total cost. The Statement of Position could impact our component and capitalization accounting for property, plant, and equipment. We continue to evaluate the impact, if any, this Statement of Position will have upon adoption.
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CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
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The accompanying notes are an integral part of these statements. CMS-39
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
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The accompanying notes are an integral part of these statements.
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CMS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these statements. CMS-42
CMS ENERGY CORPORATION
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CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
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The accompanying notes are an integral part of these statements. CMS-45
CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We have determined the need to make certain adjustments to our consolidated financial statements for the fiscal years ended December 31, 2002, December 31, 2001, and December 31, 2000. Therefore, the consolidated financial statements for 2002 and 2001 have been restated from amounts previously reported. See Note 18, Restatement and Reclassification.
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, in accordance with Revised FASB Interpretation No. 46. Intercompany transactions and balances have been eliminated. 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 not a controlling financial interest.
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 4, Uncertainties.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the transportation, processing, and storage of natural gas when services are provided. Sales taxes are recorded as liabilities and are not included in revenues. Revenues on sales of marketed electricity, natural gas, and other energy products are recognized at delivery. Mark-to-market changes in the fair values of energy trading contracts that qualify as derivatives are recognized as revenues in the periods in which the changes occur.
CAPITALIZED INTEREST: We are required to capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest for the period is limited to the actual interest cost that is incurred, and our non-regulated businesses are prohibited from imputing interest costs on any equity funds. Our regulated businesses are permitted to capitalize an allowance for funds used during construction on regulated construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an original maturity of three months or less are considered cash equivalents. At December 31, 2003, our restricted cash on hand was $201 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.
COAL INVENTORY: We use the weighted average cost method for valuing coal inventory.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the weighted average number of shares of common stock and 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 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 6, Earnings Per Share and Dividends.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities in accordance with SFAS No. 115. These debt and equity securities are classified into three categories: held-to-maturity, trading, or available-for-sale. Our investments in equity securities are classified as available-for-sale. 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. For additional details regarding financial instruments, see Note 7, 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 of the balance sheet. For subsidiaries operating in highly inflationary economies, the U.S. dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those that are hedged, are included in determining net income. The change in the foreign currency translation adjustment increased equity by $39 million for the year ended December 31, 2003. The change in the foreign currency translation adjustment decreased equity by $225 million for the year ended December 31, 2002.
GAS INVENTORY: Consumers uses the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities.
GOODWILL: Goodwill represents the excess of the purchase price over the fair value of the net assets of acquired companies. Goodwill is not amortized, but is tested annually for impairment. For additional information, see Note 3, Goodwill.
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.
MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property replacements to maintenance expense. We also charge planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements. We depreciate utility property on straight-line and units-of-production rates approved by the MPSC. The composite depreciation rates for our properties are:
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
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
disposal of spent nuclear fuel burned before April 7, 1983. As of December 31, 2003, 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 4, Uncertainties, "Other Consumers' Electric Utility Uncertainties -- Nuclear Matters."
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.
Trust Funds: MPSC orders, received in March 1999 for Big Rock and December 1999 for Palisades, provided for fully funding the decommissioning trust funds for both sites. The December 1999 order set the annual decommissioning surcharge for Palisades at $6 million. In 2003, we collected $6 million from our electric customers for the decommissioning of our Palisades nuclear plant. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability.
In December 2000, we stopped depositing funds in the Big Rock trust fund based on its funding status at that time. However, the current level of funds provided by the trust may not be adequate to fully fund the decommissioning of Big Rock. This is due in part to the DOE's failure to accept spent nuclear fuel and lower returns on the trust fund. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation, as discussed in Note 4, Uncertainties, "Other Consumers' Electric Utility Uncertainties -- Nuclear Matters." To the extent the funds are not sufficient, we would seek additional relief from the MPSC. We can make no assurance that the MPSC would grant this request.
In March 2001, we filed with the MPSC a "Report on the Adequacy of the Existing Provision for Nuclear Plant Decommissioning" for each plant reflecting decommissioning cost estimates of $349 million for Big Rock, excluding spent nuclear fuel storage costs, and $739 million for Palisades, in 2000 dollars. We are required to file the next such reports with the MPSC by March 31, 2004 for Big Rock and Palisades and we are in the process of preparing updated cost estimates.
Big Rock: In 1997, Big Rock closed permanently and plant decommissioning began. We estimate that the Big Rock site will be returned to a natural state by the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010. The following table shows our Big Rock decommissioning activities:
These activities had no material impact on net income. At December 31, 2003, we have an investment in nuclear decommissioning trust funds of $88 million for Big Rock. In addition, at December 31, 2003, we have charged $7 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.
Palisades: In December 2000, the NRC extended the Palisades operating license to March 2011 and the impact of this extension was included as part of our March 2001 filing with the MPSC.
At December 31, 2003, we have an investment in the MPSC nuclear decommissioning trust funds of $477 million for Palisades. In addition, at December 31, 2003, we have a FERC decommissioning trust fund with a balance of $10 million. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 16, Asset Retirement Obligations.
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
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
original cost is charged to accumulated depreciation and cost of removal, less salvage is recorded as a regulatory liability. For additional details, see Note 16, 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.
Property, plant, and equipment at December 31, 2003 and 2002, was as follows:
- ------------------------- (a) Capital leases presented in this table are gross amounts. Amortization of capital leases was $38 million in 2003 and $96 million in 2002.
(b) Includes unrecoverable base natural gas in underground storage of $23 million at December 31, 2003 and $23 million at December 31, 2002, which is not subject to depreciation.
(c) Included in construction costs at December 31, 2002 was $54 million, relating to the capital lease of our main headquarters. We purchased the main headquarters in November 2003.
(d) Included in net property, plant and equipment are intangible assets primarily related to software development costs, consents, and rights of way. The estimated amortization life for software development costs is seven years and other intangible amortization lives range from 50 to 75 years. Intangible assets at December 31, 2003 and 2002 were as follows:
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(e) The following table illustrates the depreciable life for electric and gas structures and improvements.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for comparative purposes. These reclassifications did not affect consolidated net income for the years presented.
RELATED-PARTY TRANSACTIONS: Consumers paid $64 million in 2003, $67 million in 2002, and $71 million in 2001 for electric generating capacity and energy from affiliates of Enterprises. CMS Energy recorded interest charges on long-term debt to related parties of $58 million in 2003. Affiliates of CMS Energy sold, stored and transported natural gas and provided other services to the MCV Partnership totaling $17 million in 2003, $41 million in 2002, and $35 million in 2001. We expensed purchases of capacity and energy from the MCV Partnership totaling $455 million in 2003, $497 million in 2002, and $488 million in 2001. For additional discussion of related-party transactions with the MCV Partnership and the FMLP, see Note 4, Uncertainties and Note 15, Summarized Financial Information of Significant Related Energy Supplier. Other related-party transactions are immaterial.
TRADE RECEIVABLES: We record our accounts receivable at fair value. Accounts deemed uncollectable are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE: We amortize premiums, discounts and expenses incurred in connection with the issuance of outstanding long-term debt over the terms of the issues. For the regulated portions of our businesses, if debt is refinanced, we amortize any unamortized premiums, discounts and expenses over the term of the new debt.
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.
In 1999, we received MPSC electric restructuring orders, which, among other things, identified the terms and timing for implementing electric restructuring in Michigan. Consistent with these orders and EITF No. 97-4, we discontinued the application of SFAS No. 71 for the energy supply portion of our business because we expected to implement ROA at competitive market based rates for our electric customers.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Since 1999, there have been significant legislative and regulatory changes in Michigan that has resulted in:
- electric supply customers of utilities remaining on cost-based rates, and
- utilities being provided the opportunity to recover Stranded Costs associated with electric restructuring, from customers who choose an alternative electric supplier.
During 2002, we re-evaluated the criteria used to determine if an entity or a segment of an entity meets the requirements to apply regulated utility accounting, and determined that the energy supply portion of our business could meet the criteria if certain regulatory events occurred. In December 2002, we received a MPSC Stranded Cost order that allowed us to re-apply regulatory accounting standard SFAS No. 71 to the energy supply portion of our business. Re-application of SFAS No. 71 had no effect on the prior discontinuation accounting, but allowed us to apply regulatory accounting treatment to the energy supply portion of our business beginning in the fourth quarter of 2002, including regulatory accounting treatment of costs required to be recognized in accordance with SFAS No. 143. For additional details, see Note 12, Asset Retirement Obligations.
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.
The following regulatory assets and liabilities, which include both current and non-current amounts, are reflected in the Consolidated Balance Sheets. We expect to recover these costs through rates over periods of up to 14 years. We recognized an OPEB transition obligation in accordance with SFAS No. 106 and established a regulatory asset for this amount that we expect to recover in rates over the next nine years.
In October 2000, we received an MPSC order authorizing us to securitize certain regulatory assets up to $469 million, net of tax, see Note 4, Uncertainties, "Consumers' Electric Utility Restructuring Matters -- Securitization." Accordingly, in December 2000, we established a regulatory asset for securitized costs of $709 million, before tax, that had previously been recorded in other regulatory asset accounts. To prepare for the financing of the securitized assets and the subsequent retirement of debt with Securitization proceeds, issuance
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
fees were capitalized as a part of Securitization costs. These issuance costs are amortized each month for up to fourteen years. The components of the unamortized securitized costs are illustrated below.
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 $939 million in 2003 and $1.659 billion in 2002.
DISCONTINUED OPERATIONS
We have discontinued the following operations:
(a) In the first quarter of 2003, we settled a liability with the purchaser of Equatorial Guinea and reversed the remaining excess reserve. This settlement resulted in a gain of $6 million after-tax, which is included in discontinued operations.
(b) As a result of the sale of CMS Oil and Gas, we recorded liabilities for certain sale indemnification obligations and other matters. In September 2003, we re-evaluated our exposure to the obligations and reduced the carrying value of these liabilities by $8 million after-tax. This adjustment is reported in discontinued operations.
(c) The Pension Plan retained pension payment obligations for Panhandle employees who were vested under the Pension Plan. Panhandle employees are no longer eligible to accrue additional benefits. Because of the significant change in the makeup of the plan, a remeasurement of the obligation at the date of sale was required. The remeasurement resulted in a $4 million increase in our 2003 OPEB expense, as well as an additional charge to accumulated other comprehensive income of approximately $34 million ($22 million after-tax) as a result of the increase in the additional minimum pension liability. Additionally, a significant
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number of Panhandle employees elected to retire as of July 1, 2003 under the CMS Energy Employee Pension Plan. As a result, we have recorded a $25 million ($16 million after-tax) settlement loss, and a $10 million ($7 million after-tax) curtailment gain, pursuant to the provisions of SFAS No. 88, which is reflected in discontinued operations.
(d) In December 2003, we began reporting the operations of our Parmelia business in discontinued operations and reduced the carrying amount of our Parmelia business to reflect fair value. The $26 million after-tax adjustment is reported in discontinued operations. We expect the sale of Parmelia to occur in 2004.
Due to lack of progress on the sale, we reclassified our international energy distribution business, which includes CPEE and SENECA, from discontinued operations to continuing operations for the years 2003, 2002, and 2001. When we initially reported the international energy distribution business as a discontinued operation in 2001, we applied APB Opinion No. 30, which allowed us to record a provision for anticipated operating losses. We currently apply FASB No. 144, which does not allow us to record a provision for future operating losses. Therefore, in the process of reclassifying the international energy distribution business to continuing operations and reversing such provisions, we increased our net loss by $3 million in 2002 and decreased our net loss by $3 million in 2001. In 2003, there was an increase to net income of $75 million as a result of reversing the previously recognized impairment loss in discontinued operations.
At December 31, 2003, "Assets held for sale" includes Parmelia, Bluewater Pipeline, and our investment in the American Gas Index fund. Although Bluewater Pipeline and the American Gas Index fund are considered held for sale, they did not meet the criteria for discontinued operations. At December 31, 2002, "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:
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The following amounts are reflected in the Consolidated Statements of Income (Loss) for discontinued operations:
The income (loss) from discontinued operations includes a reduction in asset values, a provision for anticipated closing costs, and a portion of the Parent Company's interest expense. Interest expense of $22 million for 2003, $71 million for 2002 and $86 million for 2001 has been allocated based on a ratio of the expected proceeds for the asset to be sold divided by the Parent Company's total capitalization of each discontinued operation times the Parent Company'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).
In 2003, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations:
In June 2003, we received three million shares of Southern Union common stock worth $49 million from the sale of Panhandle, a discontinued operation. In July 2003, Southern Union declared a five percent common stock dividend payable July 31, 2003, to shareholders of record as of July 17, 2003. As a result of the stock dividend, on September 30, 2003, we held 3.15 million shares of Southern Union common stock worth $54 million based on the closing price of $17.00 per share. The $2 million increase in value was recorded in dividend income. In October 2003, we sold our 3.15 million shares of Southern Union common stock to a private investor for $17.77 per share. The additional $5 million gain was recorded in other income in 2003.
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In 2002, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations:
In 2001, we sold miscellaneous assets for a pretax loss of $2 million.
In February 2004, we sold Bluewater Pipeline, a 24.9 mile pipeline that extends from Marysville, Michigan to Armada, Michigan to Bluewater Gas Storage, LLC, a subsidiary of Sempra Energy Trading Corporation. We do not expect the gain or loss on the sale to be significant.
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.
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The table below summarizes our asset impairments:
- ------------------------- (a) In September 2003, we wrote down our investment in CMS Electric and Gas' Venezuelan electric distribution utility and an associated equipment lease to reflect fair value. The impairment was based on estimates of the utility's future cash flows, incorporating certain assumptions about Venezuela's regulatory, political, and economic environment.
(b) DIG's reduced valuation was primarily a reflection of the unfavorable terms of its power purchase agreement.
(c) At CMS Generation, we determined that the fair value of our equity investments was lower than its carrying amount, and that this decline in value was other than temporary. Therefore, in accordance with APB No. 18, we recognized an impairment charge of $16 million ($11 million, net of tax).
(d) Includes development projects of $7 million ($4 million, net of tax) in 2003 that would no longer be pursued.
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:
- 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
- terminated 64 employees, including five officers. Prior to December 31, 2002, 123 employees elected severance arrangements. Of these 187 officers and employees, 65 had been terminated as of December 31, 2002. All remaining terminations were completed in 2003.
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The following table shows the amount charged to expense for restructuring costs, the payments made, and the unpaid balance of accrued costs at December 31, 2002 and December 31, 2003.
Restructuring costs for the year ended December 31, 2003, which are included in operating expenses, include $3 million of involuntary employee termination benefits.
3: GOODWILL
Our goodwill balance was $25 million at December 31, 2003 and $31 million at December 31, 2002.
CMS GAS TRANSMISSION: We recorded goodwill as an asset when we purchased Panhandle and began, over time, to expense a portion of goodwill. Effective January 1, 2002, a new accounting standard went into effect that required us to stop expensing goodwill and to test for impairment. We tested the value of the goodwill related to Panhandle for impairment by comparing the fair value of goodwill, as determined by independent appraisers, to the value on our books. The test results showed that the goodwill was impaired. We recorded a loss of $601 million ($369 million, after-tax), that was the amount by which the value on our books exceeded the fair value. In 2002, we also discontinued the operations of Panhandle; therefore, the $369 million after-tax goodwill impairment is reflected in discontinued operations. In 2003, we sold Panhandle.
CMS MST: During the third quarter of 1999, we purchased a 100 percent interest in CMS Viron and recorded goodwill. In 2002, we performed an impairment test, which determined our goodwill related to CMS Viron was impaired. In the first quarter of 2002, we recorded a loss of $15 million ($10 million, after-tax) for goodwill impairment. In 2002, we also discontinued the operations of CMS Viron; therefore, the $10 million after-tax goodwill impairment is reflected in discontinued operations. In 2003, we sold CMS Viron.
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Additionally, the following table represents net loss for the year 2001 without goodwill amortization expense.
- ------------------------- (a) Net of tax of $7 million.
4: 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 other investigations concerning round-trip trading, including an investigation by the SEC regarding round-trip trades and CMS Energy's financial statements, accounting policies and controls, and an investigation by the DOJ. CMS Energy is unable to predict the outcome of these matters, and what effect, if any, these investigations will have on its business.
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. 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
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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 the best interest of CMS Energy 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 was 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. 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 investigation by the DOJ regarding this matter. In November 2003, CMS MST and CMS Field Services (now Cantera Gas Company) entered into a settlement with the CFTC pursuant to which they paid a $16 million civil monetary penalty in connection with the inaccurate reporting of natural gas trading data to publications that compile and publish price indices. The settlement resolves all matters investigated by the CFTC involving CMS Energy, including round-trip trading. CMS Energy neither admits nor denies the CFTC's findings in the settlement order. 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. The plaintiff in the Texas-Ohio case has agreed to extend the time for all defendants to answer or otherwise respond until after the multi district court litigation ("MDL") panel decides whether to take the case. There is currently pending in the Nevada federal district court a MDL matter involving seven complaints originally filed in various state courts in California. These complaints make allegations similar to those in the CMS-59
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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.
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 are likely to seek to remove this action from the California federal district court and 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.
CONSUMERS' UNCERTAINTIES
Several business trends or uncertainties may affect Consumers' 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 conclusions about the causes of the August 14, 2003 blackout, including exposure to liability, increased regulatory requirements, and new legislation,
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to purchased power price increases,
- responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel,
- potential adverse appliance service plan ruling or related legislation,
- 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.
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Other
- pending litigation regarding PURPA qualifying facilities, and
- pending litigation and government investigations.
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. It submitted these rules to the EPA for approval in the first quarter of 2003. The EPA has yet to approve the Michigan rules. If the EPA does not approve the Michigan rules, 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 December 31, 2003, we have incurred $446 million in capital expenditures to comply with the EPA regulations and anticipate that the remaining $325 million of capital expenditures will be incurred 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 a 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.
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.
Future clean air regulations requiring emission controls for sulfur dioxide, nitrogen oxides, mercury, and nickel may require additional capital expenditures. Total expenditures will depend upon the final makeup of the new regulations.
Water: The EPA has proposed changes to the rules that govern generating plant cooling water intake systems. The proposed rules will require significant reduction in fish killed by operating equipment. The proposed rules are scheduled to become final in the first quarter of 2004 and some of our facilities would be required to comply by 2006. We are studying the proposed 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
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the total liability for the known Superfund sites will be between $1 million and $9 million. As of December 31, 2003, 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 in regard to the PSCR plan case. In February 2004, the judge ruled on the motion and deferred to the primary jurisdiction of the MPSC. This ruling effectively suspends the lawsuit until the MPSC rules. 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: In June 2000, the Michigan legislature passed electric utility restructuring legislation known as the Customer Choice Act. This act:
- allows all customers to choose their electric generation supplier effective January 1, 2002,
- provides 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,
- 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 CMS-62
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achieve the increased transmission capacity required under the Customer Choice Act. The MPSC found that once the planned projects were completed and verification was submitted, a utility was in technical compliance. 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 PLAN: In 1998, we submitted a plan for electric ROA to the MPSC. In March 1999, the MPSC issued orders generally supporting the plan. The Customer Choice Act states that the MPSC orders issued before June 2000 are in compliance with this act and enforceable by the MPSC. Those MPSC orders:
- allow electric customers to choose their supplier,
- authorize recovery of net Stranded Costs from ROA customers and implementation costs from all customer classes, and
- confirm any voluntary commitments of electric utilities.
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 March 2004, alternative electric suppliers are providing 735 MW of load. This amount represents nine percent of the total distribution load and an increase of 42 percent compared to March 2003.
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. 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 of approximately 0.4 cent per kWh to ROA customers and eliminates securitization offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh for secondary service customers. We are seeking similar recovery of Stranded Costs due to ROA customers leaving our system and are encouraged by this ruling.
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
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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 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 prior to 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, $50 million for the twelve months ended December 31, 2003, and $52 million for the twelve months ended December 31, 2002, 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. The MPSC rejected the portion of the application related to pension costs. The MPSC based its decision on the reasoning that a rebounding economy and stock market could potentially reverse recent Pension Plan losses. Also, the MPSC rejected Palisades expenditures previously not securitized as eligible securitized costs; therefore, these costs will be included in a future electric rate case proceeding with the MPSC and as a component of the 2002 net Stranded Cost calculation. 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 financing order will become effective after acceptance by us and 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.
We are authorized by the MPSC 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 and we have not recorded regulatory assets to recognize the future recovery of such costs.
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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 in 2002, and for approval of a net Stranded Cost recovery charge. Our net Stranded Costs incurred in 2002 are estimated to be $38 million with the issuance of Securitization bonds that include Clean Air Act investments, or $85 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. We cannot predict how the MPSC will rule on our request for the recoverability of Stranded Costs.
Implementation Costs: Since 1997, we have incurred significant electric utility restructuring 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.
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 December 31, 2003, $2 million of additional implementation costs and $19 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. Cash recovery from customers is expected to begin after the rate cap period expires. The rate cap expired for large commercial and industrial customers on December 31, 2003. We have asked to include implementation costs through December 31, 2000 in the pending Securitization case. If approved, the sale of Securitization bonds will allow for the recovery of a significant portion of these costs. We cannot predict the amount the MPSC will approve as allowable costs.
Also, we are pursuing authorization at the FERC for 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. In May 2003, the FERC issued an order denying MISO's request for authorization to reimburse us. In June 2003, we filed a joint petition with MISO for rehearing with the FERC, which the FERC denied in September 2003. We appealed the FERC ruling at the United States Court of Appeals for the District of Columbia and are pursuing other potential means of recovery at the FERC. In conjunction with our appeal of the September order denying recovery, MISO agreed to file a request with the FERC seeking authority to reimburse METC. As part of the contract for the sale of our former transmission system, should the FERC approve the new MISO filing, METC is contractually obligated to flow-through to us the full amount of any Alliance RTO start-up costs that it is authorized to recover by FERC. We cannot predict the outcome of the
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appeal process, the MISO request, or the ultimate amount, if any, FERC will allow us to collect for implementation 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 the remaining open items will impact 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, transmission rates charged to us are fixed by contract at current levels through December 31, 2005, and are subject to FERC ratemaking thereafter. However, we are subject to certain additional MISO surcharges, which are estimated to be $15 million in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
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. Approximately 100,000 of our 1.7 million electric customers were without power for approximately 24 hours as a result of the disturbance. We incurred $1 million of immediate expense as a result of the blackout. We continue to cooperate with investigations of the blackout by several federal and state agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC report found no evidence to suggest that the events in Michigan or actions taken by the Michigan utilities or transmission operators were factors contributing to the cause of the blackout. Also in November 2003, the United States and Canadian power system outage task force preliminarily reported that the primary cause of the blackout was due to transmission line contact with trees in areas outside of Consumers' operating territory. 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. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations to improve electric transmission reliability. The key recommendations are as follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is not, to submit annual reports on vegetation management beginning March 2005 and improve technology over various milestones throughout
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2004. These recommendations could result in increased transmission costs payable by transmission customers in the future. The financial impacts of these recommendations are not currently quantifiable.
PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC were in proposal status during 2002 and 2003. The performance standards were placed into Michigan law in January 2004 and became effective on February 9, 2004. They relate to restoration after an outage, safety, and customer relations. During 2002 and 2003, Consumers monitored and reported to the MPSC its 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 value of such incentive cannot be determined at this point as the performance standards do not contain an approved incentive mechanism. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. We cannot predict the likely effects of the financial incentive or penalties, if any, on us.
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 option 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 December 31, 2003, 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 $20 million for unexpired capacity and energy contracts. Currently, we have a reserve margin of 5 percent, or supply resources equal to 105 percent of projected summer peak load for summer 2004. We are in the process of securing the additional capacity needed to meet our summer 2004 reserve margin target of 11 percent (111 percent of projected summer peak load). The total premium costs of electricity call option and capacity and energy contracts for 2003 were approximately $10 million.
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 cap, 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
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steam to Dow. We hold, through two wholly owned subsidiaries, the following assets related to the MCV Partnership and MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the MCV Partnership, and
- CMS Holdings holds, through FMLP, a 35 percent lessor interest in the MCV Facility.
Our consolidated retained earnings include undistributed earnings from the MCV Partnership, which at December 31, 2003 are $245 million and at December 31, 2002 are $226 million.
Summarized Statements of Income for CMS Midland and CMS Holdings
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 MPSC cost-recovery orders. The remaining liability associated with the loss totaled $27 million at December 31, 2003, $53 million at December 31, 2002, and $77 million at December 31, 2001. 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
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MCV Facility's generating availability remains at the maximum 98.5 percent level, our cash underrecoveries associated with the PPA could be as follows:
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 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 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 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 our equity interest in the MCV Partnership may be affected negatively.
Under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and 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 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 exercise 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 equity interest 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 equity investment in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility on an economic basis depending 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. We requested that the MPSC provide interim approval while it conducts a full review of the plan. The MPSC has
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scheduled a prehearing conference with respect to the MCV resource conservation plan for April 2004. We cannot predict if or when the MPSC will approve our request.
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 our recovery of capacity payments. Natural gas prices have been historically volatile. 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. Therefore, we cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our equity interest in the MCV Partnership.
NUCLEAR MATTERS: Big Rock: Significant progress continues to be made in the decommissioning of Big Rock. We submitted the License Termination Plan to the NRC staff for review in April 2003. System dismantlement and building demolition are on schedule to return the 560-acre site to a natural setting for unrestricted use in early 2006. The NRC and Michigan Department of Environmental Quality continue to find that all decommissioning activities at Big Rock are being performed in accordance with applicable regulatory and license requirements.
Seven transportable dry casks have been loaded with spent nuclear fuel and an eighth cask has been loaded with high-level radioactive waste material. These dry casks will remain onsite until the DOE moves the material to a national spent nuclear fuel repository.
Palisades: In July 2003, the NRC completed its mid-cycle plant performance assessment of Palisades. The mid-cycle assessment for Palisades covered the period from January 1, 2003 through the end of July 2003. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. Based on the plant's performance, only regularly scheduled inspections are planned through September 2004.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of December 31, 2003, we have loaded 18 dry casks with spent nuclear fuel and we will need to load additional dry casks by the fall of 2004 in order to continue operation. Palisades currently has three empty dry casks onsite, with storage pad capacity for up to seven additional loaded dry casks. We anticipate that transportable dry casks, along with more storage pad capacity, will be available by fall 2004.
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 CMS-70
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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 storage and disposal should be placed in an independent trust. The complaint also asks the MPSC to take additional actions. In May 2003, Consumers and other named utilities each filed motions to dismiss the complaint. We are unable to predict the outcome of this matter.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL, totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $26 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 $10.862 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 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 from 2004 to 2005, and total an estimated $177 million. Our coal transportation contracts expire from 2004 to 2007, and total an estimated $139 million. Long-term coal supply contracts account for approximately 60 to 90 percent of our annual coal requirements. In 2003, coal purchases totaled $265 million of which $207 million (78 percent of the tonnage requirement) was under long-term contract. We supplement our long-term contracts with spot-market purchases.
Power Supply, Capacity, and Transmission: As of December 31, 2003, we had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2004 and 2005 totaling $8 million. We also had commitments to purchase capacity and energy under long-term power purchase agreements with various generating plants including the MCV Facility. These contracts require monthly capacity payments based on the plants' availability or deliverability. These payments for 2004 through 2030 total an
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estimated $14.483 billion, undiscounted, which includes $11.381 billion related to the MCV Facility. These payments exclude the obligations that Consumers has with the Genesee, Grayling, and Filer City generating plants because these entities are consolidated for CMS Energy under FASB Interpretation No. 46. 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.
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 MPSC approved rates charged to our customers. As of December 31, 2003, we have recorded a liability of $44 million, net of $38 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 February 2004, the parties in the case reached a tentative settlement agreement that would result in a GCR disallowance of $11 million for the GCR period. Interest on the disallowed amount from April 1, 2003 through February 2004, at the Consumers' authorized rate of return, adds $1 million to the cost of the settlement. We believe this settlement agreement will be executed by the parties in the case in the near future and approved by the MPSC. A reserve was recorded in December 2003.
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In July 2003, the MPSC approved a settlement agreement authorizing us to increase our gas cost recovery for the remainder of the current GCR plan year (August 2003 through March 2004) and to apply a quarterly ceiling price adjustment, based on a formula that tracks changes in NYMEX natural gas prices. The terms of the settlement allow a GCR ceiling price of $6.11 per mcf. Our GCR is $5.36 per mcf for March 2004 bills.
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 its dividend payments to CMS Energy, to a maximum of $190 million annually during the period that Consumers receives 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. The MPSC is not bound by these recommendations and will consider the issues anew after receipt of exceptions and replies to the exception filed by the parties in response to the Proposal for Decision.
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 independent of the 2003 gas rate case. 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.
OTHER CONSUMERS' GAS UTILITY UNCERTAINTIES
COMMITMENTS FOR GAS SUPPLIES: We enter into contracts to purchase gas and gas transportation from various suppliers for our natural gas business. These contracts have expiration dates that range from 2004 to 2007. Our 2003 gas purchases totaled 248 bcf at a cost of $1.379 billion. At the end of 2003, we estimate our gas purchases for 2004 to be 235 bcf, of which 22 percent is covered by existing fixed price contracts and 37 percent is covered by indexed price contracts that are subject to price variations. The remaining 2004 gas purchases will be made at market prices at the time of purchase.
OTHER CONSUMERS' 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.
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
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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 believes that Integrum's claims are without merit. CMS Energy will defend itself vigorously but cannot predict the outcome of this lawsuit.
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 reached an agreement in principle with the U.S. Coast Guard to settle this matter for $475,000.
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 CUSTOMER DISPUTES: As a result of the continued delays in the DIG project becoming fully operational, DIG's customers, Ford Motor Company, and Rouge Industries, asserted claims that the continued delays relieve them of certain contractual obligations, totaling $43 million. In addition, Ford and/or Rouge asserted several other commercial claims against DIG relating to operation of the DIG plant. In February 2003, Rouge filed an Arbitration Demand against DIG and CMS MST Michigan L.L.C. with the American Arbitration Association. Rouge was seeking a total of approximately $27 million, plus additional accrued damages at the time of any award, plus interest. More specifically, Rouge was seeking at least $20 million under a Blast Furnace Gas Delivery Agreement in connection with DIG's purported failure to declare a Blast Furnace Gas Delivery Date within a reasonable time period, plus approximately $7 million for assorted damage claims under several legal theories. As part of this arbitration, DIG filed claims against Rouge and Ford, and Ford filed claims for unspecified amounts against DIG. In October 2003, Rouge filed bankruptcy under Chapter 11 of the United States Bankruptcy Code and as a result, the arbitration was subject to the automatic stay imposed by the Bankruptcy Code. OAO Severstal, which has acquired substantially all of Rouge's assets, has indicated it will continue operations at the Rouge site and will honor the contractual obligations to pay for the steam and electricity DIG and CMS MST Michigan L.L.C. provide. In January 2004, DIG and CMS MST Michigan L.L.C. entered into a
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settlement agreement with Ford and Rouge to resolve all outstanding claims between the parties, including the arbitration claims and DIG and CMS MST Michigan L.L.C.'s claims in the Rouge bankruptcy. The settlement was approved by the bankruptcy court. Under the settlement, Ford paid DIG $12 million cash and Rouge and Ford paid DIG and CMS MST Michigan L.L.C. a total of $3.8 million owed by Rouge for steam and electricity supplied to Rouge prior to the filing of the bankruptcy petition.
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 resident 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 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 will appeal this judgment.
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 December 31, 2003, 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 2.94 pesos per U.S. dollar was $264 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.
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 CMS-75
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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 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.
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5: FINANCINGS AND CAPITALIZATION
CMS Energy's Long-term debt as of December 31 follows:
- -------------------------
(a) These notes are putable to CMS Energy by the note holders at par on July 15, 2008, July 15, 2013 and July 15, 2018, and are convertible at the holder's option into CMS Energy Common Stock at $10.671 per share under certain circumstances, none of which currently are probable to occur. CMS Energy intends to file a registration statement with the SEC by October 16, 2004, relating to the resale of the notes and the convertibility into common stock.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(b) $29 million Series D, $112 million Series E, and $104 million Series F have been called and redeemed through February 15, 2004.
(c) Represents the weighted average interest rate at December 31, 2003.
(d) 2018 maturity is subject to successful remarketing by Consumers after June 15, 2005.
(e) Callable at par.
(f) Maturity date uncertain.
LONG-TERM DEBT -- RELATED PARTIES:
Long-term debt -- related parties as of December 31, 2003 follows:
DEBT ISSUANCES: The following is a summary of long-term debt issuances during 2003:
- ------------------------- (bps -- basis points), (GCP -- General corporate purposes)
(a) These notes are putable to CMS Energy by the note holders at par on July 15, 2008, July 15, 2013 and July 15, 2018, and are convertible at the holder's option into CMS Energy Common Stock at $10.671 per share under certain circumstances, none of which currently are probable to occur. CMS Energy intends to file a registration statement with the SEC by October 16, 2004, relating to the resale of the notes and the convertibility into common stock.
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(b) CMS Energy intends to file a registration statement with the SEC by March 14, 2004, to permit note holders to exchange their securities for ones that will be registered under the Securities Act of 1933.
(c) CMS Energy used the net proceeds to retire revolving debt and redeem a portion of a 6.75 percent Senior note due January 2004.
(d) Consumers used the net proceeds to fund the maturity of a $250 million bond, to fund a $32 million option call payment, and for general corporate purposes.
(e) Consumers used the net proceeds to prepay a portion of a term loan that was due to mature in July 2004.
(f) Consumers used the net proceeds to pay off a $150 million term loan, to pay off $50 million balance on a term loan that was due to mature in July 2004, and for general corporate purposes.
(g) Consumers used the net proceeds to purchase its headquarters building and pay off the capital lease.
(h) Refer to "Regulatory Authorization for Financings" below for details about Consumers' FERC debt authorization.
(i) Consumers filed a registration statement with the SEC in December 2003 to permit holders of these FMBs to exchange their bonds for FMBs that are registered under the Securities Act of 1933. The exchange offer was completed on February 13, 2004.
DEBT MATURITIES: The aggregate annual maturities for long-term debt for the next five years are:
DEBT COVENANT RESTRICTIONS: The indenture pursuant to our GTNs contains certain provisions that can trigger a limitation on our consolidated indebtedness. The limitation can be activated when our consolidated leverage ratio, as defined in the indenture (essentially the ratio of consolidated debt to consolidated capital), exceeds 0.75 to 1.0. At June 30 and September 30, 2003, our consolidated leverage ratio was 0.76 to 1.0. As a result, we were subject to certain debt limitations. At December 31, 2003, the ratio was 0.72 to 1, and we were no longer subject to the debt limitations.
The indenture under which Senior notes are issued and certain other debt agreements contain provisions requiring us to maintain interest coverage ratios, and debt to earnings ratios. We were in compliance with these ratios, as defined, at December 31, 2003.
CMS ENERGY CREDIT FACILITY: CMS Energy has a $185 million revolving credit facility with banks. This facility matures on May 21, 2005. This facility provides letter of credit support for Enterprises' subsidiary activities, principally credit support for project debt. Enterprises provides funds to cash collateralize the letters of credit issued through this facility. As of December 31, 2003, approximately $165 million of letters of credit were issued under this facility and the cash used to collateralize the letters of credit is included on the Consolidated Balance Sheet as Restricted cash.
REGULATORY AUTHORIZATION FOR FINANCINGS: At December 31, 2003, 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 December 31, 2003, 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.
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With the granting of authorization, FERC waived its competitive bid/negotiated placement requirements applicable to the long-term securities authorization. The authorizations expire on June 30, 2004.
SHORT-TERM FINANCINGS: CMS Energy has a $190 million revolving credit facility with banks. The facility is secured by our investment in Enterprises and Consumers. The interest rate of the facility is LIBOR plus 325 basis points. This facility expires in November 2004. At December 31, 2003, all of the $190 million is available.
Consumers has a $400 million revolving credit facility with banks. The facility is secured with first mortgage bonds. The interest rate of the facility is LIBOR plus 175 basis points. This facility expires in March 2004 with two annual extensions at Consumers' option, which would extend the maturity to March 2006. At December 31, 2003, $390 million is available for general corporate purposes, working capital, and letters of credit.
At December 31, 2002, Consumers had $457 million of bank notes outstanding at a weighted average interest rate of 4.50 percent.
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.
POLLUTION CONTROL REVENUE BONDS: In January 2004, Consumers amended the PCRB indentures to add an auction rate interest mode and switched to that mode for the two floating rate bonds. Under the auction rate mode, the bonds' interest rate will be reset every 35 days. While in the auction rate mode, no letter of credit liquidity facility is required and investors do not have a put right.
PREFERRED STOCK ISSUANCE: In December 2003, CMS Energy issued 5 million shares of 4.50 percent cumulative convertible preferred stock. Each share has a liquidation value of $50.00 and is convertible into CMS Energy common stock at the option of the holder under certain circumstances. The initial conversion price is $9.893 per share, which translates into 5.0541 shares of common stock for each share of preferred stock converted. The annual dividend of $2.25 per share is payable quarterly, in cash, in arrears commencing March 1, 2004. We used the net proceeds of $242 million to retire other long-term debt in January 2004 and February 2004. We have agreed to file a shelf registration with the SEC by November 5, 2004, covering resales of the preferred stock and of common stock issuable upon conversion of the preferred stock.
SALE OF SUBSIDIARY INTEREST: In December 2003, we sold, in a private placement, a non-voting preferred interest in an indirect subsidiary of CMS Enterprises that owns certain gas pipeline and power generation assets. CMS Energy received $30 million for the preferred interest, of which $19 million has been recorded as an addition to other paid-in capital (deferred gain) and $11 million has been recorded as a preferred stock issuance.
WARRANTS: We granted warrants to purchase 204,000 shares of our common stock to a third party and expensed $1 million in 2003. The warrants which are fully vested are exercisable for seven years at an exercise price of $8.25 per share.
CAPITALIZATION: The authorized capital stock of CMS Energy consists of 250 million shares of CMS Energy Common Stock and 10 million shares of CMS Energy Preferred Stock, $.01 par value.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PREFERRED STOCK OF SUBSIDIARY: The follow table describes Consumers' Preferred Stock outstanding:
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARIES: CMS Energy and Consumers each formed various statutory wholly owned business trusts for the sole purpose of issuing preferred securities and lending the gross proceeds to the parent companies. The sole assets of the trusts are debentures of the parent company with terms similar to those of the preferred security. Summarized information for company-obligated mandatorily redeemable preferred securities is as follows:
- ------------------------- (a) We determined that we do not hold the controlling financial interest in 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. For additional details, see "Long-Term Debt -- Related Parties" within this Note and Note 17, Implementation of New Accounting Standards.
(b) The trusts must redeem the securities at a liquidation value of $25 per share ($50 per share for QUIPS (c)), which is equivalent to the carrying cost, plus accrued but unpaid distributions when the securities are paid at maturity or upon any earlier redemption. Prior to an early redemption date, the securities could be redeemed at market value.
(c) Represents 3,450,000 shares of Quarterly Income Preferred Securities (QUIPS) that are convertible into 1.2255 shares of CMS Energy Common Stock (equivalent to a conversion price of $40.80). Conversion is unlikely as of December 31, 2003, based on the market price of CMS Energy's Common Stock of $8.52. If conversion were to occur in the future, the securities would be converted into 4,227,975 shares of CMS Energy Common Stock. Effective July 2001, we can revoke the conversion rights if certain conditions are met.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(d) In August 2003, 8,800,000 units of outstanding 7.25 percent Premium Equity Participating Security Units (CMS Energy Trust III) were converted to 16,643,440 newly issued shares of CMS Energy Common Stock.
Each trust receives payments on the debenture it holds. Those receipts are used to make cash distributions on the preferred securities the trust has issued.
The securities allow CMS Energy and Consumers the right to defer interest payment on the debentures, and, as a consequence, the trusts would defer dividend payments on the preferred securities. Should the parent companies exercise this right, they cannot declare or pay dividends on, or redeem, purchase or acquire, any of their capital stock during the deferral period until all deferred dividends are paid in full.
In the event of default, holders of the preferred securities would be entitled to exercise and enforce the trusts' creditor rights against CMS Energy and Consumers, which may include acceleration of the principal amount due on the debentures. The parent companies have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with each parent company's obligations under the debentures, related indenture and trust documents, provide full and unconditional guarantees for the trust's obligations under the preferred securities.
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. The amounts sold were $297 million at December 31, 2003 and $325 million at December 31, 2002. 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:
DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at December 31, 2003, Consumers had $373 million of unrestricted retained earnings available to pay common dividends. However, covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. Through December 31, 2003, we received the following common stock dividend payments from Consumers:
As of December 18, 2003, Consumers is also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. Because all of the $218 million of common stock dividends to CMS Energy were paid prior to December 18, 2003, Consumers was not out of compliance with this new restriction for 2003. In February 2004, Consumers paid a $78 million common stock dividend.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For additional details on the potential cap on common dividends payable included in the MPSC Securitization order, see Note 4, Uncertainties, "Consumers' Electric Utility Rate Matters -- Securitization." Also, for additional details on the cap on common dividends payable during the current interim gas rate relief period, see Note 4, 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 describe our guarantees at December 31, 2003:
- ------------------------- (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. Included in this amount is a $739 million indemnification obligation related to the sale of CMS Oil and Gas facilities in Equatorial Guinea which expired January 3, 2004, and for which no loss occurred. 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. In addition, $25 million has been recorded prior to 2003 in accordance with SFAS No. 5.
(c) Recourse provision indicates the approximate recovery from third parties including assets held as collateral.
The following table provides additional information regarding our guarantees at December 31, 2003:
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 $521 million as of December 31, 2003. 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:
- ------------------------- (a) At December 31, 2003, we had $175 million of cash collateralized letters of credit and the cash used to collateralize the letters of credit is included in Restricted cash on the Consolidated Balance Sheets.
6: EARNINGS PER SHARE AND DIVIDENDS
The following table presents the basic and diluted earnings per share computations.
- ------------------------- (a) Due to antidilution, the computation of diluted earnings per share excluded the conversion of Trust Preferred Securities.
(b) Due to antidilution, the computation of diluted earnings per share excluded shares of outstanding stock options and warrants of 0.3 million for the year ended 2003 and 0.2 million for the year ended 2001.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In January 2003, the Board of Directors suspended the payment of common stock dividends. However, in 2002, we paid the following dividends per share:
7: 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 investments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar investments or other valuation techniques. The carrying amount of all long-term financial instruments, except as shown below, approximate fair value. For additional details, see Note 1, Corporate Structure and Accounting Policies.
- ------------------------- (a) Settlement of long-term debt is generally not expected until maturity.
(b) We determined that we do not hold the controlling financial interest in 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, refer to Note 5, Financings and Capitalization, "Long-Term Debt -- Related Parties" and Note 17, 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.
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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 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. 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:
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The fair value of other than trading derivative contracts is included in either Other Assets or Other Liabilities 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 investment in the MCV Partnership is included in Investments -- Midland Cogeneration Venture Limited Partnership on the Consolidated Balance Sheets. Effective April 1, 2002, the MCV Partnership changed its accounting for derivatives. For additional details see Note 15, Summarized Financial Information of Significant Related Energy Supplier. The fair value of derivative contracts associated with other equity investments is included in Enterprises Investments on the Consolidated Balance Sheets.
Cumulative Effect of Change in Accounting Principle: On January 1, 2001, upon initial adoption of the derivatives standard, we recorded a $10 million, net of tax, cumulative effect adjustment as an increase in accumulated other comprehensive income. This adjustment relates to the difference between the fair value and recorded book value of contracts related to gas call options, gas fuel for generation swap contracts, and interest rate swap contracts that qualified for hedge accounting prior to the initial adoption of SFAS No. 133 and our proportionate share of the effects of adopting SFAS No. 133 related to our equity investments in the MCV Partnership and Taweelah. Based on the initial transition adjustment of $21 million, net of tax, recorded in accumulated other comprehensive income at January 1, 2001, Consumers reclassified to earnings $12 million as a reduction to the cost of gas, $1 million as a reduction to the cost of power supply, $2 million as an increase in interest expense, and $8 million as an increase in other revenues for the twelve months ended December 31, 2001. CMS Energy recorded $12 million as an increase in interest expense during 2001, which includes the $2 million of additional interest expense at Consumers. The difference between the initial transition adjustment and the amounts reclassified to earnings represents an unrealized loss in the fair value of the derivative instruments since January 1, 2001, resulting in a decrease of accumulated other comprehensive income. We also recorded a $7 million, net of tax, cumulative effect adjustment as an increase to earnings. This adjustment relates to our proportionate share of the difference between the fair value and the recorded book value of interest rate swaps at Taweelah, and financial gas and supply contracts that were required to be accounted for as derivatives as of January 1, 2001.
In June and December 2001, the FASB issued guidance that resolved the accounting for certain utility industry contracts. As a result, we recorded a $3 million, net of tax, cumulative effect adjustment as an unrealized loss, decreasing accumulated other comprehensive income, and on December 31, 2001, recorded an $11 million, net of tax, cumulative effect adjustment as a decrease to earnings. These adjustments relate to the difference between the fair value and the recorded book value of certain electric call option contracts.
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. For additional details regarding this loss see Note 17, Implementation of New Accounting Standards.
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.
Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA, could be material to the financial statements.
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Our electric business also uses gas option and swap contracts to protect against price risk due to the fluctuations in the market price of gas used as fuel for generation of electricity. These contracts are financial contracts that are used to offset increases in the price of potential gas purchases. These contracts do not qualify for hedge accounting. Therefore, we record any change in the fair value of these contracts directly in earnings as part of power supply costs.
For the year ended December 31, 2003, the unrealized gain in accumulated other comprehensive income related to our proportionate share of the effects of derivative accounting related to our equity investment in the MCV Partnership is $10 million, net of tax. We expect to reclassify this gain, if this value remains, as an increase to earnings from equity method investees during the next 12 months.
GAS CONTRACTS: Our gas utility business uses fixed price 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.
ENERGY TRADING ACTIVITIES: Through December 31, 2002, CMS MST's wholesale power and gas trading activities were accounted for under the mark-to-market method of accounting. Under mark-to-market accounting, energy-trading contracts are reflected at fair market value, net of reserves, with unrealized gains and losses recorded as an asset or liability in the Consolidated Balance Sheets. These assets and liabilities are affected by the timing of settlements related to these contracts, current-period changes from newly originated transactions and the impact of price movements. Changes in fair value are recognized as revenues in the Consolidated Statements of Income in the period in which the changes occur. 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 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
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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 at year end:
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 7.4 percent at December 31, 2003 and 4.0 percent at December 31, 2002.
Certain equity method investees have issued interest rate swaps. These instruments are not included in this analysis, but can have an impact on financial results. See discussion of these instruments in Note 18, Restatement and Reclassification.
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.
There were no outstanding foreign exchange contracts at December 31, 2003. The notional amount of the outstanding foreign exchange contracts at December 31, 2002 was $1 million Canadian. The estimated fair value of the foreign exchange and option contracts at December 31, 2002 was zero.
8: INCOME TAXES
CMS Energy and its subsidiaries file a consolidated federal income tax return. Income taxes generally are allocated based on each company's separate taxable income. We practice deferred tax accounting for temporary differences in accordance with SFAS No. 109, Accounting for Income Taxes.
U.S. income taxes are not recorded on the undistributed earnings of foreign subsidiaries that have been or are intended to be reinvested indefinitely. Upon distribution, those earnings may be subject to both U.S. income taxes (adjusted for foreign tax credits or deductions) and withholding taxes payable to various foreign countries. We annually determine the amount of undistributed foreign earnings that we expect will remain invested indefinitely in foreign subsidiaries. Cumulative undistributed earnings of foreign subsidiaries for which income taxes have not been provided totaled approximately $106 million at December 31, 2003. It is impractical to estimate the amount of unrecognized deferred income taxes or withholding taxes on these undistributed earnings. Also, at December 31, 2003 and 2002, we recorded U.S. income taxes with respect to temporary differences between the book and tax bases of foreign investments that were determined to be no longer essentially permanent in duration.
The Job Creation and Worker Assistance Act of 2002 provided corporate taxpayers a 5-year carryback of tax losses incurred in 2001 and 2002. As a result of this legislation, we carried back consolidated 2001 and 2002 tax losses to tax years 1996 through 1999 to obtain refunds totaling $250 million. The tax loss carryback, however, resulted in a reduction in AMT credit carryforwards that previously had been recorded as deferred tax assets in the amount of $47 million. This non-cash reduction in AMT credit carryforwards was reflected in our tax provision in 2002.
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We use ITC to reduce current income taxes payable, and amortize ITC over the life of the related property. AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2003, we had AMT credit carryforwards in the amount of $214 million that do not expire, tax loss carryforwards in the amount of $1.151 billion that expire from 2021 through 2023. In addition, we had capital loss carryforwards in the amount of $29 million that expire in 2007, and general business credit carryforwards in the amount of $42 million that primarily expire in 2005, for which valuation allowances have been provided.
During the fourth quarter of 2000, we wrote down the value of our investment in Loy Yang by $329 million ($268 million after-tax). We have now concluded the tax benefit associated with the write-down should have been reduced by $38 million. Accordingly, retained earnings as of January 1, 2001 have been reduced by this amount. For additional details, see Note 18, Restatement and Reclassification.
The significant components of income tax expense (benefit) on continuing operations consisted of:
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The principal components of deferred tax assets (liabilities) recognized in the consolidated balance sheet are as follows:
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The actual income tax expense (benefit) on continuing operations differs from the amount computed by applying the statutory federal tax rate of 35 percent to income before income taxes as follows:
- ------------------------- (a) The increased income tax expense for 2003 is primarily attributable to the valuation reserve provisions for the possible loss of general business credit, capital loss, and charitable contributions carryforwards.
(b) Because of the small size of the net income in 2003, the effective tax rate is not meaningful. Changes in the effective tax rate in 2002 from 2001 resulted principally from the reduction in AMT credit carryforwards and the recording of U.S. taxes on undistributed earnings and basis differences of foreign subsidiaries.
9: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan to key management employees based on their contributions to the successful management of the Company. The Plan includes the following type of awards for common stock:
- restricted shares of common stock,
- stock options, and
- stock appreciation rights.
Restricted shares of common stock are outstanding shares with full voting and dividend rights. These awards vest over five years at the rate of 25 percent per year after two years. Some restricted shares are subject to achievement of specified levels of total shareholder return and are subject to forfeiture if employment terminates before vesting. Restricted shares vest fully if control of CMS Energy changes, as defined by the plan.
Stock options give the holder the right to purchase common stock at a given price over an extended period of time. Stock appreciation rights give the holder the right to receive common stock appreciation, which is defined
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as the excess of the market price of the stock at the date of exercise over the grant date price. Our stock options and stock appreciation rights are valued at market price when granted. All options and rights may be exercised upon grant and they expire up to ten years and one month from the date of grant.
Our Performance Incentive Stock Plan was amended in January 1999. It uses the following formula to grant awards:
- Up to five percent of our common stock outstanding at January 1 each year less:
+ the number of shares of restricted common stock awarded, and
+ common stock subject to options granted under the plan during the immediately preceding four calendar years.
- the number of shares of restricted common stock awarded under this plan cannot exceed 20 percent of the aggregate number of shares reserved for awards, and
- forfeiture of shares previously awarded will increase the number of shares available to be awarded under the plan.
Awards of up to 2,240,247 shares of CMS Energy Common Stock may be issued as of December 31, 2003.
The following table summarizes the restricted stock and stock options granted to our key employees under the Performance Incentive Stock Plan:
At December 31, 2003, 186,522 of the 1,264,028 shares of restricted common stock outstanding are subject to performance objectives. Compensation expense included in income for restricted stock was $2 million for 2003, less than $1 million in 2002, and $1 million in 2001.
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The following table summarizes our stock options outstanding at December 31, 2003:
The number of stock options exercisable was 5,795,145 at December 31, 2003, 5,007,329 at December 31, 2002 and 3,760,883 at December 31, 2001.
In December 2002, we adopted the fair value based method of accounting for stock-based employee compensation, under SFAS No. 123, as amended by SFAS No. 148. We elected to adopt the prospective method recognition provisions of this Statement, which applies the recognition provisions to all awards granted, modified, or settled after the beginning of the fiscal year that the recognition provisions are first applied.
The following table summarizes the weighted average fair value of stock options granted:
- ------------------------- (a) For 2002, there were two stock option grants.
The stock options fair value is estimated using the Black-Scholes model, a mathematical formula used to value options traded on securities exchanges. The following assumptions were used in the Black-Scholes model:
- ------------------------- (a) For 2002, there were two stock option grants.
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We recorded $5 million as stock-based employee compensation cost for 2003 and $4 million for 2002. All stock options vest at date of grant. If stock-based compensation costs had been determined under SFAS No. 123 for the year ended December 31, 2001, consolidated net loss and pro forma net loss would have been as follows:
10: 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 all of our employees, and the employees of our subsidiaries, including Panhandle. The Pension Plan's assets are not distinguishable by company.
In June 2003, we sold Panhandle to Southern Union Panhandle Corp. No portion of the Pension Plan assets were transferred with the sale and Panhandle employees are no longer eligible to accrue additional benefits. The Pension Plan retained pension payment obligations for Panhandle employees that were vested under the Pension Plan.
The sale of Panhandle resulted in a significant change in the makeup of the Pension Plan. A remeasurement of the obligation was required at the date of sale. The remeasurement further resulted in the following:
- an increase in OPEB expense of $4 million for 2003, and
- an additional charge to accumulated other comprehensive income of $34 million ($22 million after-tax) as a result of the increase in the additional minimum pension liability. Due to large contributions, the additional minimum pension liability was eliminated as of December 31, 2003.
Additionally, a significant number of Panhandle employees elected to retire as of July 1, 2003 under the CMS Energy Employee Pension Plan. As a result, we have recorded a $25 million ($16 million after-tax) settlement loss, and a $10 million ($7 million after-tax) curtailment gain, pursuant to the provisions of SFAS No. 88, which is reflected in discontinued operations.
In 2003, a substantial number of non-Panhandle retiring employees also elected a lump sum payment instead of receiving pension benefits as an annuity over time. Lump sum payments constitute a settlement under SFAS
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No. 88. A settlement loss must be recognized when the cost of all settlements paid during the year exceeds the sum of the service and interest costs for that year. We recorded settlement loss of $59 million ($39 million after-tax) in December 2003.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code; SERP trust earnings are taxable and trust assets are included in consolidated assets. Trust assets were $66 million at December 31, 2003, and $57 million at December 31, 2002. The assets are classified as other non-current assets. The Accumulated Benefit Obligation for SERP was $62 million at December 31, 2003 and $54 million at December 31, 2002.
OPEB: Retiree health care costs at December 31, 2003 are based on the assumption that costs would increase 8.5 percent in 2003. The rate of increase is expected to be 7.5 percent for 2004. The rate of increase is expected to slow to an estimated 5.5 percent by 2010 and thereafter.
The health care cost trend rate assumption significantly affects the estimated costs recorded. A one-percentage point change in the assumed health care cost trend assumption would have the following effects:
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 (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.
EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premium for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. EISP expense was $1 million in 2003 and $2 million in 2002. As of December 31, 2003, the Accumulated Benefit Obligation of the EISP was $3 million.
The measurement date for all plans is December 31.
Assumptions: The following table recaps the weighted-average assumptions used in our retirement benefits plans to determine benefit obligations and net periodic benefit cost:
- ------------------------- (a) We determine our long-term rate of return by considering historical market returns, the current and future economic environment, the capital market principles of risk and return, and the expertise of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future CMS-96
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expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed periodically for reasonability and appropriateness.
Costs: The following table recaps the costs incurred in our retirement benefits plans:
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
- ------------------------- (a) At December 31, 2003, there were 4,970,000 shares of CMS Energy Common Stock in the Pension Plan assets with a fair value of $42 million, and 414,000 shares in the OPEB plan assets with a fair value of $4 million. At December 31, 2002, there were 5,099,000 shares of CMS Energy Common Stock in the Pension Plan assets with a fair value of $48 million, and 284,000 shares in the OPEB plan assets with a fair value of $3 million.
(b) At February 29, 2004, the Pension Plan assets were 66 percent equity, 34 percent fixed income. We plan to contribute $72 million to our OPEB plan in 2004. We estimate a contribution of $26 million to our Pension Plan in 2004.
We have established a target asset allocation for our Pension Plan assets of 65 percent equity and 35 percent fixed income investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor's 500 Index, with a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a Foreign Equity Index Fund. Fixed income investments are diversified across investment grade instruments of both government and corporate issuers. Annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation.
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We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the rate making process for Consumers, and through direct contributions from the non-utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in an Standard & Poor's 500 Index fund. The fixed income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.
Reconciliations: The following table reconciles the funding of our retirement benefit plans with our retirement benefit plans' liability:
- ------------------------- (a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003. This Act 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 have decided to defer recognizing the effects of the Act in our 2003 financial statements, as permitted by FASB Staff Position No. 106-1. When accounting guidance is issued, our retiree health benefit obligation may be adjusted.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.055 billion exceeded the value of the Pension Plan assets and net balance sheet liability at December 31, 2002. As a result, we recorded an additional minimum liability, including an intangible asset of $53 million, and $373 million of accumulated other
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comprehensive income. In August 2003, we made our planned contribution of $210 million to the Pension Plan. In December 2003, we made an additional contribution of $350 million to the Pension Plan that eliminated the additional minimum liability. The Accumulated Benefit Obligation for the pension plan was $1.019 billion at December 31, 2003.
11: LEASES
We lease various assets including vehicles, railcars, construction equipment, an airplane, computer equipment, and buildings. We have both full-service and net leases. A net lease requires us to pay for taxes, maintenance, operating costs, and insurance. Most of our leases contain options at the end of the initial lease term to:
- purchase the asset at the then fair value of the asset, or
- renew the lease at the then fair rental value.
Minimum annual rental commitments under our non-cancelable leases at December 31, 2003 were:
Consumers is authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. Operating lease charges were $14 million in 2003, $13 million in 2002, and $15 million in 2001.
Capital lease expenses were $17 million in 2003, $20 million, in 2002 and $26 million in 2001. Included in the $26 million for 2001 is $7 million of nuclear fuel lease expense. In November 2001, our nuclear fuel capital leasing arrangement expired. At termination of the lease, we paid the lessor $48 million, which was the lessor's remaining investment at that time.
In April 2001, we entered into a lease agreement for the construction of an office building to be used as the main headquarters for CMS Energy and Consumers in Jackson, Michigan. In November 2003, we exercised our purchase option under the lease agreement and bought the office building with proceeds from a $60 million term loan.
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12: JOINTLY OWNED REGULATED UTILITY FACILITIES
We are required to provide only our share of financing for the jointly owned utility facilities. The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant's undivided ownership interest. The following table indicates the extent of our investment in jointly owned regulated utility facilities:
13: 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. The most significant of these investments is our 50 percent interest in Jorf Lasfar, and our 49 percent interest in the MCV Partnership (Note 15). Our investment in Jorf Lasfar is $256 million at December 31, 2003 and $240 million at December 31, 2002. Net income from these investments included undistributed earnings of $41 million in 2003 and $39 million in 2002 and distributions in excess of earnings of $68 million in 2001. Summarized financial information of the MCV Partnership is disclosed separately in
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Note 15, Summarized Financial Information of Significant Related Energy Supplier. Listed below is the summarized income and balance sheet information for these investments.
Income Statement Data
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Balance Sheet Data
14: 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 its subsidiary, Consumers. The gas utility segment consists of regulated activities like transportation, storage, and distribution of natural gas in the state of Michigan through its 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.
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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. We restated 2002 and 2001 information due to the management reorganization and the change in our business strategy in 2003 from five to three operating segments.
Reportable Segments
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Geographic Areas(c)
- ------------------------- (a) Amounts includes a portion of Consumers' assets for both the Electric and Gas utility units.
(b) Amounts include electric restructuring implementation plan, capital leases for nuclear fuel, purchase of nuclear fuel and other assets and electric DSM costs. Amounts also include a portion of Consumers' capital expenditures for plant and equipment that both the electric and gas utility units use.
(c) Revenues are based on the country location of customers.
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15: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER
Under the PPA with the MCV Partnership discussed in Note 4, Uncertainties, our 2003 obligation to purchase electric capacity from the MCV Partnership provided 15 percent of our owned and contracted electric generating capacity. Summarized financial information of the MCV Partnership follows:
Statements of Income
Balance Sheets
- ------------------------- (a) Revenue from Consumers totaled $514 million in 2003, $557 million in 2002, and $550 million in 2001.
(b) On April 1, 2002, the MCV Partnership implemented a new accounting standard for derivatives. As a result, the MCV Partnership began accounting for several natural gas contracts containing an option component at fair value. The MCV Partnership recorded a $58 million cumulative effect adjustment for the change in accounting principle as an increase to earnings. CMS Midland's 49 percent ownership share was $28 million ($18 million after-tax), which is reflected as a change in accounting principle on our Consolidated Statements of Income (Loss).
(c) Receivables from Consumers totaled $40 million for December 31, 2003 and $44 million for December 31, 2002.
(d) FMLP is the sole beneficiary of a trust that is the lessor in a long-term direct finance lease with the MCV Partnership. CMS Holdings holds a 46.4 percent ownership interest in FMLP. The MCV Partnership's
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lease obligations, assets, and operating revenues secure FMLP's debt. The following table summarizes obligation and payment information regarding the direct finance lease.
(e) CMS Midland's recorded investment in the MCV Partnership includes capitalized interest, which we are expensing over the life of our investment in the MCV Partnership. The financing agreements prohibit the MCV Partnership from distributing any cash to its owners until it meets certain financial test requirements. We do not anticipate receiving a cash distribution in the near future.
16: 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. Accretion of $1 million related to the Big Rock and Palisades' profit component included in the estimated cost of removal was expensed for 2003.
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
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reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would be $381 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. The pro forma effect on results of operations would not have been material for the year ended December 31, 2002.
The following tables describe our assets that have legal obligations to be removed at the end of their useful life.
- ------------------------- (a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and CMS Field Services.
Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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
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accumulated depreciation, were reclassified as regulatory liabilities in the accompanying consolidated balance sheets.
17: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES: Amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for contracts entered into or modified after June 30, 2003. Implementation of this statement has not impacted our Consolidated Financial Statements.
SFAS NO. 150, ACCOUNTING FOR CERTAIN FINANCIAL INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY: Establishes standards for how we classify and measure certain financial instruments with characteristics of both liabilities and equity. The statement requires us to classify financial instruments within its scope as liabilities rather than mezzanine equity, the area between liabilities and equity. SFAS No. 150 became effective July 1, 2003.
We have five Trust Preferred Securities outstanding as of December 31, 2003 that are issued by our affiliated trusts. Each trust holds a subordinated debenture from the parent company. The terms of the debentures are identical to those of the trust-preferred securities, except that the debenture has an explicit maturity date. The trust documents, in turn, require that the trust be liquidated upon the repayment of the debenture. The preferred securities are redeemable upon the liquidation of the subsidiary; therefore, are considered equity in the financial statements of the subsidiary.
At their October 29, 2003 Board meeting, the FASB deferred the implementation of the portion of SFAS No. 150 relating to mandatorily redeemable noncontrolling interests in subsidiaries when the noncontrolling interests are classified as equity in the financial statements of the subsidiary. Our Trust Preferred Securities are included in the deferral action.
Upon adoption of FASB Interpretation No. 46, we determined that our trusts that issue Trust Preferred Securities should be deconsolidated and reported as long-term debt -- related parties. Refer to further discussion under FASB Interpretation No. 46, Consolidation of Variable Interest Entities.
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 the 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 cumulative effect of change in accounting principle loss of $23 million, net of tax, for the year ended December 31, 2003.
EITF ISSUE NO. 01-08, DETERMINING WHETHER AN ARRANGEMENT CONTAINS A LEASE: In May 2003, the EITF reached consensus in EITF Issue No. 01-08 requiring both parties to a transaction, such as power purchase agreements, to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning July 1, 2003.
Prospective accounting under EITF Issue No. 01-08, could affect the timing and classification of revenue and expense recognition. Certain product sales and service revenue and expenses may be required to be reported as rental or leasing income and/or expenses. Transactions deemed to be capital lease arrangements would be included on our balance sheet. The adoption of EITF Issue No. 01-08 has not impacted our results of operations, cash flows, or financial position.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
EITF ISSUE NO. 03-04, ACCOUNTING FOR CASH BALANCE PENSION PLANS: In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address the accounting for certain cash balance pension plans. EITF Issue No. 03-04 concluded that certain cash balance plans be accounted for as defined benefit plans under SFAS No. 87, Employers' Accounting for Pensions. The EITF requirements must be applied as of our next plan measurement date after issuance, which is December 31, 2003. In 2003, we started a cash balance pension plan that covers employees hired after June 30, 2003. We do account for this plan as a defined benefit plan under SFAS No. 87 and comply with EITF Issue No. 03-04. For further information, see Note 10, Retirement Benefits.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: 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 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 provides an implementation deferral, until the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the first quarter of 2004 for all entities other than special purpose entities. Special-purpose entities must apply either FASB Interpretation No. 46 or Revised FASB Interpretation No. 46 for the first reporting period that ends after December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have adopted Revised FASB Interpretation No. 46 for all entities other than the MCV Partnership and FMLP. We continue to evaluate and gather information regarding those entities. We will adopt the provisions of Revised FASB Interpretation No. 46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest in the MCV Partnership and FMLP, we would consolidate their assets, liabilities, and activities, including $700 million of non-recourse debt, into our financial statements. Financial covenants under our financing agreements could be impacted negatively after such a consolidation. As a result, it may become necessary to seek amendments to the relevant financing agreements to modify the terms of certain of these covenants to remove the effect of this consolidation, or to refinance the relevant debt. As of December 31, 2003, our investment in the MCV Partnership was $419 million and our investment in the FMLP was $224 million.
We determined that we have the controlling financial interest in three entities that are determined to be variable interest entities. We have 50-percent partnership interest in T.E.S Filer City Station Limited Partnership, Grayling Generating Station Limited Partnership, and 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 provide us with the controlling financial interest as defined by the Interpretation. Therefore, we have consolidated these partnerships into our consolidated financial statements for the first time as of December 31, 2003. At December 31, 2003, total assets consolidated for these entities are $227 million and total liabilities are $164 million, including $128 million of non-recourse debt. At December 31, 2003, CMS Energy has outstanding letters of credit and guarantees of $5 million relating to these entities. At December 31, 2003, minority interest recorded for these entities totaled $36 million.
We also determined that we do not hold the controlling financial interest in 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
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
eliminated due to deconsolidation. As a result of the deconsolidation, we have reflected $684 million of long-term debt -- related parties and have 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 non-controlling interests in four other variable interest entities. FASB Interpretation No. 46 requires us to disclose certain information about these entities. The chart below details our involvement in these entities at December 31, 2003:
- ------------------------- (a) At December 31, 2003, we recorded 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 $27 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 $59 million, Loy Yang currency translation losses of $110 million, net of tax, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $146 million. Included in the $146 million is 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.
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 is expected to be presented for FASB clearance in 2004 and would be applicable for fiscal years beginning after December 15, 2004. An asset classified as property, plant, and equipment asset often comprises multiple parts and costs. A component accounting policy determines the level at which those parts are recorded. Capitalization of certain costs related to property, plant, and equipment are included in the total cost. The Statement of Position could impact our component and capitalization accounting for property, plant, and equipment. We continue to evaluate the impact, if any, this Statement of Position will have upon adoption.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
18: RESTATEMENT AND RECLASSIFICATION
We have determined the need to make certain adjustments to our consolidated financial statements for the fiscal years ended December 31, 2002, December 31, 2001, and December 31, 2000. Therefore, the consolidated financial statements for 2002 and 2001 have been restated from amounts previously reported. The table below summarizes the significant adjustments and the effects on our consolidated net loss.
INTEREST ALLOCATION RECLASSIFICATION FOR INTERNATIONAL ENERGY DISTRIBUTION: Due to lack of progress on the sale, we reclassified our international energy distribution business, which includes CPEE and SENECA, from discontinued operations to continuing operations for the years 2003, 2002, and 2001. When we initially reported the international energy distribution business as a discontinued operation in 2001, we applied APB Opinion No. 30, which allowed us to record a provision for anticipated operating losses. We currently apply FASB No. 144 which does not allow us to record a provision for future operating losses. Therefore, in the process of reclassifying the international energy distribution business to continuing operations and reversing such provisions, we increased our net loss by $3 million in 2002 and decreased our net loss by $3 million in 2001.
DERIVATIVES RELATED TO THE EQUITY METHOD INVESTMENTS: Some of our equity affiliates hold derivative instruments, including interest rate swaps and other similar instruments. Some of these instruments have been accounted for as cash flow hedges, with changes in the fair value of the hedges reported in accumulated other comprehensive income in 2003, 2002 and 2001. However, in late 2003 it was determined that certain of our equity affiliates did not formally designate their instruments as hedges, or did not do so in a timely manner, in accordance with SFAS No. 133. Therefore, the changes in the fair value of the hedges should have been reported in earnings in 2003, 2002, and 2001. As a result, the effects of the changes in the fair value of the hedges require restatement. Our proportionate share of the adjustments increased our net loss by $27 million in 2002 and increased our net loss by $14 million in 2001.
BALANCE SHEET IMPACTS: The most significant effects on our consolidated balance sheets include the reclassification of International Energy Distribution from "held for sale" to continuing operations and the change in our investments due to the correction of the derivatives discussed above.
During the fourth quarter of 2000, we wrote down the value of our investment in Loy Yang by $329 million ($268 million after-tax). We have now concluded that the tax benefit associated with the write-down should have been reduced by $38 million. Accordingly, our retained deficit as of January 1, 2001 increased by this amount.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables present the effects of the adjustments we made to our consolidated financial statements for the fiscal years ended December 31, 2002 and December 31, 2001, as well as effects of reclassifying Marysville and Parmelia into discontinued operations.
CONSOLIDATED STATEMENTS OF INCOME
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED BALANCE SHEETS
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
19: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
We have determined the need to make certain adjustments to our consolidated financial statements for the quarterly periods of 2003 and 2002. Therefore, the consolidated financial statements for the quarterly periods of 2003 and 2002 have been restated from amounts previously reported.
- ------------------------- (a) Net of tax
(b) Sum of the quarters may not equal the annual earnings per share due to changes in shares outstanding
(c) Based on New York Stock Exchange -- Composite transactions
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables present the effects of the adjustments we made to our consolidated financial statements for the quarterly periods of 2003 and 2002, as well as the effects of reclassifying Marysville and Parmelia into discontinued operations.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The table below summarizes the significant adjustments and the effect on consolidated net income (loss) by quarter.
- ------------------------- (a) We continue to pursue the sale of International Energy Distribution, which includes CPEE and SENECA, but due to the slow progress on the sale, we have reclassified this entity from discontinued operations to continuing operations for the years 2003, 2002, and 2001. When we initially reported the international energy distribution business as a discontinued operation in 2001, we applied APB Opinion No. 30, which allowed us to record a provision for anticipated closing costs and operating losses. We currently apply FASB No. 144 which does not allow us to record a provision for future operating losses. Therefore, in the process of reclassifying the international energy distribution business to continuing operations and reversing such provisions, we increased our net loss by $3 million in 2002 and decreased our net loss by $3 million in 2001. In 2003, there was an increase to net income of $75 million as a result of reversing the previously recognized impairment loss in discontinued operations.
(b) We determined that certain equity method investees inappropriately accounted for interest rate swaps as hedges. For additional details, see Note 18, Restatement and Reclassification.
(c) We determined the net loss recorded in the second quarter of 2003 relating to the sale of Panhandle, reflected as Discontinued Operations, was understated by approximately $14 million, net of tax. The understatement occurred because we did not recognize through our second quarter 2003 earnings an unrealized loss related to certain Panhandle interest rate hedging derivative instruments. Pursuant to SFAS No. 133, the unrealized loss was accounted for in Other Comprehensive Income, but needed to be recognized through earnings upon the sale of Panhandle.
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REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders CMS Energy Corporation
We have audited the accompanying consolidated balance sheets of CMS Energy Corporation (a Michigan corporation) and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income (loss), common stockholders' equity and cash flows for each of three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The financial statements of Midland Cogeneration Venture Limited Partnership and Jorf Lasfar Energy Company S.C.A., which represent investments accounted for under the equity method of accounting, have been audited by other auditors (the other auditors for 2001 for Midland Cogeneration Venture Limited Partnership have ceased operations) whose reports have been furnished to us; insofar as our opinion on the consolidated financial statements relates to the amounts included for Midland Cogeneration Venture Limited Partnership and Jorf Lasfar Energy Company S.C.A., respectively, it is based solely on their reports.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of CMS Energy Corporation and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Notes 16 and 17 to the consolidated financial statements, in 2003, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations", EITF Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts" and of Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities". As discussed in Notes 3, 9 and 15 to the consolidated financial statements, in 2002, the Company adopted the provisions of SFAS No. 142, "Goodwill and Other Intangibles", SFAS No. 148, "Accounting for Stock-Based Compensation" and Midland Cogeneration Venture Limited Partnership adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted.
As discussed in Note 18 to the consolidated financial statements, the Company restated its 2002 and 2001 financial statements.
/s/ ERNST & YOUNG LLP
Detroit, Michigan February 27, 2004
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REPORT OF INDEPENDENT AUDITORS
We have audited the accompanying balance sheets of Jorf Lasfar Energy Company S.C.A (the "Company") as of December 31, 2003, 2002 and 2001, and the related statements of income, of stockholders' equity and of cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Jorf Lasfar Energy Company S.C.A at December 31, 2003, 2002 and 2001, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Price Waterhouse
Casablanca, Morocco, February 10, 2004
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REPORT OF INDEPENDENT AUDITORS
To the Partners and the Management Committee of Midland Cogeneration Venture Limited Partnership:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of the Midland Cogeneration Limited Partnership (a Michigan limited partnership) and its subsidiaries (MCV) at December 31, 2003 and 2002, and the results of their operations and their cash flows for the each of the two years ended December 31, 2003 and 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of MCV's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of MCV for the year ended December 31, 2001, were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated January 18, 2002.
As explained in Note 2 to the financial statements, effective April 1, 2002, Midland Cogeneration Venture Limited Partnership changed its method of accounting for derivative and hedging activities in accordance with Derivative Implementation Group ("DIG") Issue C-16.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan February 18, 2004
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THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ARTHUR ANDERSEN REPORT AND THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners and the Management Committee of the Midland Cogeneration Venture Limited Partnership:
We have audited the accompanying consolidated balance sheets of the MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP (a Michigan limited partnership) and subsidiaries (MCV) as of December 31, 2001 and 2000, and the related consolidated statements of operations, partners' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of MCV's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Midland Cogeneration Venture Limited Partnership and subsidiaries as of December 31, 2001 and 2000, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1, 2001, Midland Cogeneration Venture Limited Partnership changed its method of accounting related to derivatives and hedging activities.
/s/Arthur Andersen LLP
Detroit, Michigan, January 18, 2002
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[CONSUMERS ENERGY LOGO]
2003 FINANCIAL STATEMENTS
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CONSUMERS ENERGY COMPANY
SELECTED FINANCIAL INFORMATION
- ------------------------- (a) See Notes 1 and 2 in the notes to the consolidated financial statements.
(b) Effective December 31, 2003, Trust Preferred Securities are classified on the balance sheets as Long-term debt -- related parties.
(c) Effective November 2002, Michigan Gas Storage Company was merged into Consumers.
(d) Excludes off-system transportation customers.
(e) For additional details on the reclassification of non-legal cost of removal, see Note 12, Asset Retirement Obligation, "Reclassification of Non-Legal Cost of Removal." Following is the amount of cost of removal reclassified from accumulated depreciation to a regulatory liability by year: $983 million in 2003; $907 million in 2002; $870 million in 2001; $896 million in 2000; and $874 million in 1999.
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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. 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.
In 2003, we continued to implement our strategy centered around growing a healthy utility in Michigan. We have taken advantage of historically low interest rates to extend maturities and refinance our debt at lower cost. We completed financing and refinancing transactions to resolve liquidity concerns at the start of 2003. In addition, we contributed $501 million to our defined benefit pension plan. This should result in lower pension costs in the future.
At the foundation of our financial progress was exceptional operating performance. For the second consecutive year, our Michigan gas utility earned the J.D. Power and Associates award for highest residential customer satisfaction with natural gas services in the Midwest. Independent evaluators, like J.D. Power and Associates recognize value and our regulators do too. The MPSC authorized an annual increase in our gas utility rates of $56 million in late 2002, and an additional interim annualized $19 million rate increase in 2003.
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 March 2004, we lost 735 MW or nine percent of our electric business to these alternative electric suppliers. We expect the loss to grow to over 1,000 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, and we have asked the MPSC to approve it quickly.
We also are focused on further reducing our business risk and leverage, 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.
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FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-K 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:
- achievement of capital expenditure reductions and cost savings,
- 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 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,
- 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,
- 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, CE-4
- 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
2003 COMPARED TO 2002: Net income in 2003 was reduced $141 million as compared to 2002 for several reasons. Higher electric and gas operating costs in 2003 were responsible for $80 million of the reduction in net income. Increased operating costs include $53 million in higher pension and other benefit costs, see Note 7, Retirement Benefits, $12 million of increased depreciation expense reflecting higher levels of plant in service, and $7 million of increased amortization expense associated with securitized regulatory assets. Amortization expense is recognized as principal is repaid to the Securitization bondholders.
A significant reduction in 2003 electric deliveries also contributed to reduced net income. Milder weather during the summer air conditioning season, and a continuation of the trend of commercial and industrial customers switching from us to other electric suppliers, impacted net income negatively by $27 million in 2003 versus 2002. Increased costs of borrowing reduced 2003 net income by $23 million, reflecting higher levels of debt, and higher average interest rates.
Our ownership interest in the MCV Partnership reflects a $27 million reduction, as compared to 2002, in the fair value of certain gas contracts held by the MCV Partnership. The fair value of these contracts is adjusted through earnings in accordance with SFAS No. 133. For additional details on SFAS No. 133, see Note 4, Financial and Derivative Instruments.
The 2003 decrease in net income also reflects a $7 million charge at CMS Holdings to reflect the loss of certain tax credits.
Finally, contrary to 2002, net income in 2003 did not reflect any gains or losses associated with asset sales. In 2002, gains primarily associated with the sale of the electric transmission system contributed $31 million to net income.
On the positive side, 2003 net income increased $25 million as compared to 2002 due to a full year of higher gas tariff rates, as authorized by the MPSC in late 2002. Lower general taxes in 2003 contributed an additional $8 million to net income during the year. The reduction in general taxes primarily reflects a MSBT credit received from the State of Michigan associated with the construction of our headquarters on a qualifying Brownfield site. Our ability to manage our electric power supply costs also provided additional net income in 2003. Lower average fuel costs and the availability of higher market prices for our excess capacity increased net income by $17 million as compared to 2002.
2002 COMPARED TO 2001: Net income increased $190 million as compared to 2001. This increase was the result of several factors. Reduced electric power costs in 2002 were responsible for $85 million of the increase in net income. This reduction in power costs was due primarily to higher cost replacement power purchased in 2001 because of a refueling outage and an unscheduled forced outage at Palisades. Lower prices for power options and dispatchable capacity contracts purchased in 2002 also contributed to the reduction in power costs.
In 2002, gains primarily associated with the sale of the electric transmission system contributed $31 million to net income. Net income in 2001 did not reflect any gains or losses associated with asset sales.
Under SFAS No. 133, certain MCV gas contracts are adjusted, through earnings, to reflect fair value. Earnings received by our ownership interest in the MCV Partnership reflect a $25 million increase, compared to 2001, in the fair value of these contracts held by the MCV Partnership. Net income also increased as a result of an
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$11 million adjustment to electric call option and option-like contracts booked in 2001, due to SFAS No. 133 implementation.
Increased electric deliveries to the higher margin residential and commercial customers contributed $27 million to net income in 2002. The interim and final gas rate orders issued in 2001 and 2002 increased net income by $16 million. Offsetting these increases to net income is a $9 million decrease resulting from the recognition of a historic gas inventory adjustment in the cumulative amount of 4 bcf.
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
ELECTRIC DELIVERIES: In 2003, electric revenues decreased, reflecting lower deliveries. Most significantly, sales volumes to commercial and industrial customers were 5.6 percent lower than in 2002, a result of these sectors' continued switching to alternative electric suppliers as allowed by the Customer Choice Act. The decrease in revenue is also the result of reduced deliveries to higher-margin residential customers, from a milder summer's impact on air conditioning usage. Overall, electric deliveries, including transactions with other wholesale marketers and other electric utilities, decreased 0.4 billion kWh or 1.1 percent.
In 2002, electric revenue increased by $41 million from the previous year, despite lower deliveries. This was due primarily to increased deliveries to higher-margin residential customers as a result of a significantly warmer summer's impact on air conditioning usage. Deliveries, including transactions with other wholesale marketers and other electric utilities, decreased 0.3 billion kWh or 0.7 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our recovery of power supply costs was fixed, 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 2003, this difference between power supply-related revenues and actual power supply costs benefited operating income by $26 million more than it had in 2002. This increase is primarily the result of increased intersystem revenues due to higher market prices and sales made from surplus capacity. The efficient operation of our generating plants and lower priced purchased power further decreased power supply costs.
In 2002, as compared to 2001, power supply costs and related revenues increased operating income due primarily to reduced purchased power costs because the Palisades plant returned to service in 2002, following an extended 2001 shutdown.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In 2003, net operating expenses and non-commodity revenue decreased operating income by $80 million versus 2002. This decrease relates to increased
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pension and other benefit costs of $54 million, a scheduled refueling outage at Palisades, and higher transmission costs. More plant in service increased depreciation costs by $8 million, and $11 million of higher amortization expense from securitized assets further contributed to decreased operating income. Slightly offsetting the increased operating expenses were higher non-commodity revenues associated with other income.
In 2002, net operating expenses and non-commodity revenue decreased operating income by $21 million compared with 2001. The decrease primarily related to higher transmission expenses and increased depreciation costs from more plant in service.
ASSET SALES: The reduction in operating income from asset sales for 2003 versus 2002, and the increase in operating income from asset sales for 2002 versus 2001 reflect the $31 million pretax gain associated with the 2002 sale of our electric transmission system and the $7 million pretax gain associated with the 2002 sale of nuclear equipment from the cancelled Midland project.
GENERAL TAXES: In 2003, general taxes decreased from 2002 due primarily to reductions in MSBT expense, resulting primarily from a tax credit received from the State of Michigan associated with construction of the new corporate headquarters on a qualifying Brownfield site. In 2002, general taxes increased over 2001 due to increases in MSBT and property tax accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily to higher average debt levels, but also because of higher average interest rates. In 2002, fixed charges decreased versus 2001 because of a reduction in long-term debt.
INCOME TAXES: In 2003, income tax decreased versus 2002 due primarily to lower earnings by the electric utility. In 2002, income tax expense increased versus 2001 due primarily to increased earnings.
GAS UTILITY RESULTS OF OPERATIONS
GAS DELIVERIES: In 2003, gas deliveries, including miscellaneous transportation, increased 4.1 bcf or 1.1 percent versus 2002. Despite increased system deliveries, gas revenues actually declined by $1 million. Colder weather during the first quarter of 2003 increased deliveries to the residential and commercial sectors. Increased deliveries resulted in a $6 million increase in gas revenues. However, the revenue increase was offset by a $7 million gas loss adjustment recorded as a reduction to gas revenues.
In 2002, gas revenues increased by $21 million from the previous year. System deliveries, including miscellaneous transportation, increased 9.4 bcf or 2.6 percent. The increase was due primarily to colder weather that increased deliveries to the residential and commercial sectors.
GAS RATE INCREASE: In November 2002, the MPSC issued a final gas rate order authorizing a $56 million annual increase to gas tariff rates. As a result of this order, 2003 gas revenues increased $39 million. In 2002, gas rate increases led to increased gas revenues of $25 million over 2001.
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GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: In 2003, gas wholesale and retail services and other gas revenues increased $1 million. The $1 million increase includes primarily the following two items. In 2003, we reversed a $4 million reserve, originally recorded in 2002, for non-physical gas title tracking services. In addition, in 2003, we reserved $11 million for the settlement agreement associated with the 2002-2003 GCR disallowance. For additional details regarding both of these issues, see the Gas Utility Business Uncertainties in the "Outlook" section of this MD&A.
OPERATION AND MAINTENANCE: In 2003, operation and maintenance expenses increased versus 2002 due to increases in pension and other benefits costs of $27 million and additional expenditures on safety, reliability, and customer service. In 2002, operation and maintenance expenses increased versus 2001 due to the recognition of gas storage inventory losses and additional expenditures on customer reliability and service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In 2003, the net of general tax expense, depreciation expense, and other income decreased operating income primarily because of increases in depreciation expense from increased plant in service. In 2002, the net of general tax expense, depreciation expense, and other income decreased operating income primarily because of increases in MSBT and property tax expense accruals.
FIXED CHARGES: In 2003, fixed charges increased versus 2002 due primarily to higher average debt levels, but also because of higher average interest rates. In 2002 versus 2001, fixed charges decreased due to lower long-term debt levels.
INCOME TAXES: In 2003 versus 2002, income tax expense increased due to reduced income tax expense in 2002. The 2002 reduction was attributable to flow-through accounting on plant, property and equipment as required by past MPSC rulings. In 2002, income tax expense increased versus 2001 due primarily to increased earnings of the gas utility.
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,
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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 contracted 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 availability 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 a regulatory out provision under the MCV Partnership power purchase agreement. This provision obligates us 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 equity, and
- eliminate our underrecoveries for capacity and 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 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 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 our equity interest in the MCV Partnership 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 equity 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 an economic basis depending on 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. We requested that the MPSC provide interim approval while it conducts a full review of the plan. The MPSC has scheduled a prehearing conference with respect to the MCV resource conservation plan for April 2004. We cannot predict if or when the MPSC will approve our request.
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 our recovery of capacity payments. Natural gas prices have been historically volatile. 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. Therefore, we cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our equity interest in the MCV Partnership.
For additional details, see Note 2, Uncertainties, "Other Electric Uncertainties -- The Midland Cogeneration Venture."
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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 December 31, 2003, we had $1.105 billion recorded as regulatory assets and $1.467 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, including our investment in CMS Energy Common Stock, 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.
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 options, 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.
Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA, 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 December 31, 2003, we
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assumed a market-based interest rate of 1 percent (six-month U.S. Treasury rate) and an average volatility rate of 79 percent to calculate the fair value of our gas call options.
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, 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.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in market interest rates):
- ------------------------- (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. The 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. The weather-based gas supply call options, along with the gas supply call and put options, are used to purchase reasonably priced gas supply. Call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Put options give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices.
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The commodity price risk sensitivity analysis was not material for the years ending December 31, 2003 and December 31, 2002.
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.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
For additional details on market risk and derivative activities, see Note 4, Financial and Derivative Instruments.
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. We implemented a cash balance plan for 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:
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.
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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.
In August 2003, we made a planned contribution of $172 million to the Pension Plan. In December 2003, we made an additional contribution of $329 million. As a result of these contributions, we reversed the additional minimum liability and the resulting decrease in equity that we charged in 2002. As of December 31, 2003, we have a prepaid pension asset of $384 million recorded on our consolidated balance sheets.
Market-Related Valuation: We determine pension expense on a market-related valuation of assets, which reduces year-to-year volatility. The market-related valuation includes investment gains or losses over a five-year period from the year in which the gains or losses occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.
The Pension Plan includes funds for our employees and our non-utility affiliates. The Pension Plan assets are not distinguishable by company. Due to the unfavorable performance of the equity markets in the past few years, as of December 31, 2003, we had cumulative losses of approximately $239 million that remain to be included in the calculation of the market-related value of assets. These unrecognized net actuarial losses may result in increases in future pension expense in accordance with SFAS No. 87.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003. This Act 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 deferring recognizing the effects of the Act in our 2003 financial statements, as permitted by FASB Staff Position No. 106-1. When accounting guidance is issued, our retiree health benefit obligation may be adjusted.
For additional details on postretirement benefits, see Note 7, Retirement Benefits.
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. Accretion of $1 million related to the Big Rock and Palisades' profit component included in the estimated cost of removal was expensed in 2003.
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.
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Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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, were reclassified as regulatory liabilities in the accompanying consolidated balance sheets.
For additional details on ARO, see Note 12, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and FERC regulate the recovery of costs to decommission our Big Rock and Palisades nuclear plants. They require, and we have established, external trust funds to finance the decommissioning of both plants. Our electric customers pay a surcharge to fund these trusts. 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. Spent fuel storage costs would not be incurred if the DOE took possession of the spent fuel. There is litigation underway to recover these costs.
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 was stopped since it was considered fully funded, subject to further MPSC review. The funds provided by the trusts, additional customer surcharges, and potential funds from DOE litigation are all required to cover fully the decommissioning costs and we currently expect that to happen. 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.
For additional details on nuclear decommissioning, see Note 1, Corporate Structure and Accounting Policies, "Nuclear Plant Decommissioning."
RELATED PARTY TRANSACTIONS
We enter into a number of significant transactions with related parties. These transactions include:
- purchases of capacity and energy from the MCV Partnership and from affiliates of Enterprises,
- sale of storage and transportation of natural gas and other services to the MCV Partnership,
- issuance of Trust Preferred Securities with Consumers' affiliated companies,
- purchases and sales of electricity and gas for generation from CMS ERM,
- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,
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- payment of parent company overhead costs to CMS Energy, and
- investment in CMS Energy Common Stock.
Transactions involving CMS Energy and its affiliates, and the sale of storage and transportation of natural gas and other services to the MCV Partnership are generally based on regulated prices, market prices or competitive bidding. Transactions involving the power supply purchases from the MCV Partnership, and certain affiliates of Enterprises, are based upon avoided costs under PURPA and competitive bidding. The payment of parent company overhead costs is based on use of accepted industry allocation methodologies.
In 2002, MTH purchased our transmission facilities. MTH is a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc., an independent company, whose management includes former executive employees of CMS Energy. The sale was based on competitive bidding. We continue to use the transmission facilities now owned by MTH, and one of our directors is currently a stockholder of Trans-Elect, Inc.
For additional details on related party transactions, see Note 1, Corporate Structure and Accounting Policies, "Related Party Transactions," Note 2, Uncertainties, "Electric Restructuring Matters - Transmission Sales," and "Other Electric Uncertainties -- The Midland Cogeneration Venture."
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 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. As a result, in 2003, 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 implemented our strategic plan, including reducing 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
SELECTED MEASURES OF LIQUIDITY AND CAPITAL RESOURCES:
In 2003, working capital was driven primarily by the following:
- cash proceeds from long-term debt issuance -- $1,603 million
partially offset by:
- cash used for long-term debt retirements, excluding current portion -- $483 million,
- cash used for pension contributions, excluding notes payable to related party -- $301 million, and
- cash used for capital expenditures -- $486 million.
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SUMMARY OF CASH FLOWS:
OPERATING ACTIVITIES:
2003: Net cash provided by operating activities decreased $755 million in 2003 primarily due to an increase in pension plan contributions of $454 million and an increase in gas inventory of $346 million due to higher gas purchases at higher prices.
2002: Net cash provided by operating activities increased $242 million in 2002 primarily due to a decrease in gas inventory of $397 million due to a lower volume of gas purchased at lower prices, combined with increased sales volume at higher prices. This increase was partially offset by an increase in accounts receivable and accrued revenue of $247 million due to a gas rate increase, colder weather in the fourth quarter of 2002, and increased electric deliveries to higher margin customer sectors.
INVESTING ACTIVITIES:
2003: Net cash used in investing activities increased $203 million in 2003 primarily due to a decrease in asset sale proceeds of $288 million resulting from the sale of METC in 2002, offset by a decrease in 2003 versus 2002 capital expenditures of $73 million as a result of our strategic plan to reduce capital expenditures.
2002: Net cash used in investing activities decreased $482 million in 2002 primarily due to a decrease in capital expenditures of $186 million as a result of our strategic plan to reduce capital expenditures, and an increase in asset sale proceeds of $298 million resulting from the sale of METC.
FINANCING ACTIVITIES:
2003: Net cash provided by financing activities increased $529 million in 2003 primarily due to an increase in net proceeds from borrowings of $490 million. For additional details on long-term debt activity, see Note 3, Financings and Capitalization.
2002: Net cash used in financing activities increased $485 million in 2002 primarily due to a decrease in proceeds from securitization bonds of $459 million and a decrease in proceeds from preferred securities of $121 million. The decrease in proceeds was partially offset by an increase in net proceeds from borrowings of $101 million. For additional details on long-term debt activity, see Note 3, Financings and Capitalization.
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OBLIGATIONS AND COMMITMENTS
The following schedule is a summary of our contractual obligations and commercial commitments. We aggregate this information into a single location so that a picture of our obligations and commitments is readily available. For additional details, see Note 2, Uncertainties, and Note 3, Financings and Capitalization.
- ------------------------- (a) Purchase obligations related to the MCV Facility PPA assume that the regulatory out provision is exercised in 2007. For additional details, see Note 2, Uncertainties, "Other Electric Uncertainties - The Midland Cogeneration Venture," "Commitments for Future Purchases," and "Gas Contingencies - Other Gas Uncertainties."
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers must obtain FERC authority to issue short and long-term securities. For additional details of Consumers' existing authority, see Note 3, Financings and Capitalization.
LONG-TERM DEBT: Details on our long-term debt issuances, retirements, and outstanding balances are presented in Note 3, Financings and Capitalization.
SHORT-TERM FINANCINGS: We have $390 million available under a revolving credit facility. At December 31, 2003, the line is available for general corporate purposes, working capital, and letters of credit. For additional details, see Note 3, Financings and Capitalization.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of leased service vehicles and 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,
- sale of accounts receivable, and
- unconditional purchase obligations.
Operating Leases: Leases of railroad cars are accounted for as operating leases.
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Non-recourse Debt: Our share of unconsolidated debt associated with partnerships and joint ventures in which we have a minority interest is non-recourse.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we currently sell up to $325 million of certain accounts receivable. For additional details, see Note 3, 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 including the MCV Facility. These contracts require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $47 million per month during 2004, including $34 million related to the MCV Facility. 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," and "Other Electric Uncertainties -- The Midland Cogeneration Venture."
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.
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at December 31, 2003, we had $373 million of unrestricted retained earnings available to pay common dividends. However, covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. Through December 31, 2003, we made the following common stock dividend payments:
As of December 18, 2003, we are also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. Because all of the $218 million of common stock dividends to
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CMS Energy were paid prior to December 18, 2003, we were not out of compliance with this new restriction for 2003. In February 2004, we paid a $78 million common stock dividend.
For additional details on the potential cap on common dividends payable included in the MPSC Securitization order, see Note 2, Uncertainties, "Electric Restructuring Matters -- Securitization." Also, 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."
CAPITAL EXPENDITURES:
We estimate the following capital expenditures, including new lease commitments, by expenditure type and by business segments during 2004 through 2006. We prepare these estimates for planning purposes and may revise them.
- ------------------------- (a) These amounts include a portion of our anticipated capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.
(b) These amounts include estimates for capital expenditures that may be required by revisions to the Clean Air Act's national air quality standards.
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.
For 2003, our electric deliveries, including delivery to customers who chose to buy generation service from an alternative electric supplier, declined 1.4 percent from 2002. This was due to a combination of warmer than normal summer weather in 2002, cooler than normal summer weather in 2003, and a decline in manufacturing activity during 2003. In 2004, we project electric deliveries to grow more than three percent. This short-term outlook for 2004 assumes higher levels of manufacturing activity than in 2003 and normal weather conditions throughout the year.
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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, and
- responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
- potential rising pension costs due to market losses and lump sum payments. For additional details, see "Accounting for Pension and OPEB" section within this MD&A.
- pending litigation and government investigations.
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,
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- 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 8.1 percent. As of December 31, 2003, we have incurred $446 million in capital expenditures to comply with these regulations and anticipate that the remaining $325 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.
Future clean air regulations requiring emission controls for sulfur dioxide, nitrogen oxides, mercury, and nickel may require additional capital expenditures. Total expenditures will depend upon the final makeup of the new regulations.
The EPA continues to make new rules. The EPA has proposed changes to the rules that govern generating plant cooling water intake systems. The proposed rules are scheduled to be final in the first quarter of 2004. We are studying the proposed 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 March 2004, alternative electric suppliers are providing 735 MW of generation supply to ROA customers. This amount represents nine percent of our distribution load and an increase of 42 percent compared to March 2003. We anticipate this upward trend to continue and expect over 1,000 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 charge a transition surcharge of approximately 0.4 cent per kWh to ROA customers and eliminates securitization offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh for secondary service customers. We are seeking similar recovery of Stranded Costs due to ROA customers leaving our system and are encouraged by this ruling. This ruling may change significantly the anticipated number of customers who choose ROA.
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 financing order will become effective after acceptance by us and resolution of any appeals.
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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 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 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 are estimated to be $38 million with the issuance of Securitization bonds that include Clean Air Act investments, or $85 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. We cannot predict how the MPSC will rule on our request 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 has reviewed and allowed certain of the implementation costs incurred through 2001, but has not authorized recovery. Depending upon the outcome of the remanded Securitization proceeding, a significant portion of the implementation costs could be recovered through the Securitization process.
Our application for $2 million of implementation costs in 2002 is currently pending approval by the MPSC. We deferred these costs as a regulatory asset. In addition to the implementation costs filed with the MPSC in 2003, we recorded an additional $2 million for total implementation costs of $91 million. Included in total implementation costs is $19 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 the rate cap period has expired. For additional information on rate caps, see "Rate Caps" within this section. Once a final financing order by the MPSC on Securitization is issued, the recoverability of the implementation costs requested will be known. We cannot predict the amounts the MPSC will approve as allowable costs. Also, we are pursuing authorization at the FERC for 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 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. In addition, we continue to pursue other potential means of recovery with FERC. We cannot predict the outcome of the appeal process or the ultimate amount, if any, the FERC will allow us to collect for implementation 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:
- a rate freeze effective through December 31, 2003, and
- rate caps effective through December 31, 2004 for small commercial and industrial customers, and 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 needed 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: Prior to 1998, the PSCR process provided for the reconciliation of actual power supply costs with power supply revenues. This process assured 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 1998, as part of the CE-22
electric restructuring efforts, the MPSC suspended the PSCR process, effective through 2001. As a result of the rate freeze imposed by the Customer Choice Act, frozen rates remained in effect until December 31, 2003, and the PSCR process remained suspended. Therefore, changes in power supply costs due to fluctuating electricity prices were not reflected in rates charged to our customers during the rate freeze period.
As a result of meeting the transmission capability expansion requirements and the market power test, we have met the requirements under the Customer Choice Act to return to the PSCR process. For additional details see Note 2, Uncertainties, "Electric Restructuring Matters -- Electric Restructuring Legislation."
Accordingly, 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 cap, 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. We continued to collect the equivalent to the Big Rock nuclear decommissioning surcharge consistent with the Customer Choice Act rate freeze in effect through December 31, 2003. Collection of the surcharge stopped, effective January 1, 2004, when the electric rate freeze expired. As a result, our electric revenues will be reduced by $35 million in 2004. However, we expect a portion of this reduction to be offset with increased electric revenues from returning to the PSCR process.
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 December 31, 2003, contracts for 301 MW of load have terminated. Of the contracts that have terminated, contracts for 64 MW have gone to an alternative electric supplier and contracts for 237 MW 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. Other new special contracts for 101 MW received interim approval from the MPSC and are awaiting final approval. All new special contracts end by January 1, 2006. We cannot predict the ultimate financial impact of changes related to these power supply contracts, or whether additional special contracts will be necessary or advisable.
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 impact 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 significantly affect:
- 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 currently quantifiable. 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.
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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. Approximately 100,000 of our 1.7 million electric customers were without power for approximately 24 hours as a result of the disturbance. We incurred $1 million of immediate expense as a result of the blackout. We continue to cooperate with investigations of the blackout by several federal and state agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC report found no evidence to suggest that the events in Michigan, or actions taken by the Michigan utilities or transmission operators, were factors contributing to the cause of the blackout. Also in November 2003, the United States and Canadian power system outage taskforce preliminarily reported that the primary cause of the blackout was due to transmission line contact with trees in areas outside of Consumers' operating territory. In December 2003, the MPSC issued an order requiring Consumers to report by April 1, 2004, the status of lines used to serve our customers, including details of vegetation trimming practices in calendar year 2003. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations to improve electric transmission reliability. The key recommendations are as follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is not, to submit annual reports on vegetation management beginning March 2005 and improve technology over various milestones throughout 2004. These recommendations could result in increased transmission costs payable by transmission customers in the future. The financial impacts of these recommendations are not currently quantifiable.
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."
PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC became effective in February 2004. The performance standards establish standards related 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 value of such incentive cannot be determined at this point as the performance standards do not contain an approved incentive mechanism. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. We cannot predict the likely effects of the financial incentive or penalties, if any, on us.
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.
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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 cost at a number of sites, including sites formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate increases,
- potential adverse appliance service plan ruling or related legislation, 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 "Accounting for Pension and OPEB" section within this MD&A, and
- pending litigation and government investigations.
Consumers sells 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, Consumers purchases gas for resale on a Btu basis. The Btu content of the gas available for purchase has increased and may result in customers using less gas for the same heating requirement. Consumers fully recovers what it spends to purchase the gas through the approved GCR. However, since the customer is using less gas on a volumetric basis, the revenue from the distribution charge (the non-gas cost portion of the customer bill) would be reduced. This could affect adversely Consumers' earnings from its gas utility. The amount of the earnings loss 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 FERC for clarification or rehearing of FERC's December 2003 order. We cannot predict the outcome of this filing.
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 February 2004, the parties in the case reached a tentative settlement agreement that would result in a GCR disallowance of $11 million for the GCR period plus $1 million accrued interest through February 2004. A reserve was recorded in December 2003. 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
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$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 rate 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. The MPSC is not bound by these recommendations and will consider the issues anew after receipt of exceptions and replies to the exception filed by the parties in response to the Proposal for Decision.
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 independent of the 2003 gas rate case. 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.
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 are in the process of filing 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.
The Michigan House of Representatives is scheduled to review the proposed legislation in 2004 that would allow us to remain in the appliance service business. In the interim, the legislature passed a bill to extend to July 1, 2004, the deadline for exiting this business. The full impact of the new code of conduct on our business will remain uncertain until the final judicial resolution of our appeal or the Michigan legislature enacts clarifying legislation.
LITIGATION AND REGULATORY INVESTIGATIONS: CMS Energy is the subject of various investigations as a result of round-trip trading transactions by CMS MST, including investigations by the United States Department of Justice and the SEC. Additionally, CMS Energy and Consumers are parties to 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.
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OTHER MATTERS
2001 GAS RATE CASE: In June 2001, we filed an application with the MPSC for a distribution service rate increase. In November 2002, the MPSC approved a $56 million annual distribution service rate increase, with an 11.4 percent authorized return on equity.
NEW ACCOUNTING STANDARDS
See Note 13, Implementation of New Accounting Standards, for discussion of new standards.
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: 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 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 provides an implementation deferral until the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the first quarter of 2004 for all entities other than special purpose entities. Special purpose entities must apply either FASB Interpretation No. 46 or Revised FASB Interpretation No. 46 for the first reporting period that ends after December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have adopted Revised FASB Interpretation No. 46 for all entities other than the MCV Partnership and FMLP. We continue to evaluate and gather information regarding those entities. We will adopt the provisions of Revised FASB Interpretation No. 46 for the MCV Partnership and FMLP in the first quarter of 2004.
If our completed analysis shows we have the controlling financial interest in the MCV Partnership and FMLP, we would consolidate their assets, liabilities, and activities, including $700 million of non-recourse debt, into our financial statements. Financial covenants under our financing agreements could be impacted negatively after such a consolidation. As a result, it may become necessary to seek amendments to the relevant financing agreements to modify the terms of certain of these covenants to remove the effect of this consolidation, or to refinance the relevant debt. As of December 31, 2003, our investment in the MCV Partnership was $419 million and our investment in the FMLP was $224 million.
We also determined that we do not hold the controlling financial interest in 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 have reflected $506 million of long-term debt -- related parties and have 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.
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 is expected to be presented for FASB clearance in 2004 and would be applicable for fiscal years beginning after December 15, 2004. An asset classified as property, plant, and equipment often comprises multiple parts and costs. A component accounting policy determines the level at which those parts are recorded. Capitalization of certain costs related to property, plant, and equipment are included in the total cost. The Statement of Position could impact our component and capitalization accounting for property, plant, and equipment. We continue to evaluate the impact, if any, this Statement of Position will have upon adoption.
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CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these statements.
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CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
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- ------------------------- (a) Cash and Cash Equivalents decreased $18 million for 2002 and $4 million for 2001 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.
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CONSUMERS ENERGY COMPANY CONSOLIDATED BALANCE SHEETS
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The accompanying notes are an integral part of these statements.
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CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ------------------------- (a) Number of shares of common stock outstanding was 84,108,789 for all periods presented.
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(b) Disclosure of Comprehensive Income: Other comprehensive income (loss)
(c) Cumulative effect of change in accounting principle, as of 1/1/01 and 7/1/01, net of tax of $9 (Note 4).
The accompanying notes are an integral part of these statements. CE-35
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, in accordance with Revised FASB Interpretation No. 46. Intercompany transactions and balances have been eliminated. 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 not a controlling financial interest.
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.
REVENUE RECOGNITION POLICY: Revenues from deliveries of electricity and natural gas, and the storage of natural gas are recognized when services are provided. Sales taxes are recorded as liabilities and are not included in revenues.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an original maturity of three months or less are considered cash equivalents. At December 31, 2003, our restricted cash on hand was $18 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.
COAL INVENTORY: We use the weighted average cost method for valuing coal inventory.
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, including our investment in CMS Energy Common Stock, are classified as available-for-sale. 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. For additional details regarding financial instruments, see Note 4, Financial and Derivative Instruments, "Financial Instruments."
GAS INVENTORY: We use the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate the potential impairment of our investments in projects and other long-lived assets, other than goodwill, based on various analyses, including the projection of undiscounted cash flows, whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the carrying amount of the investment or asset exceeds the amount of the expected future undiscounted cash flows, an impairment loss is recognized, and the investment or asset is written down to its estimated fair value.
MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property replacements to maintenance expense. We also charge planned major maintenance activities to operating expense unless the cost CE-36
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represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements. We depreciate utility property on straight-line and units-of-production rates approved by the MPSC. The composite depreciation rates for our properties are:
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 December 31, 2003, 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."
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.
Trust Funds: MPSC orders, received in March 1999 for Big Rock and December 1999 for Palisades, provided for fully funding the decommissioning trust funds for both sites. The December 1999 order set the annual decommissioning surcharge for Palisades at $6 million. In 2003, we collected $6 million from our electric customers for the decommissioning of our Palisades nuclear plant. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability.
In December 2000, we stopped depositing funds in the Big Rock trust fund based on its funding status at that time. However, the current level of funds provided by the trust may not be adequate to fully fund the decommissioning of Big Rock. This is due in part to the DOE's failure to accept spent nuclear fuel and lower returns on the trust fund. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation, as discussed in Note 2, Uncertainties, "Other Electric Uncertainties -- Nuclear Matters." To the extent the funds are not sufficient, we would seek additional relief from the MPSC. We can make no assurance that the MPSC would grant this request.
In March 2001, we filed with the MPSC a "Report on the Adequacy of the Existing Provision for Nuclear Plant Decommissioning" for each plant reflecting decommissioning cost estimates of $349 million for Big Rock, excluding spent nuclear fuel storage costs, and $739 million for Palisades, in 2000 dollars. We are required to file the next such reports with the MPSC by March 31, 2004 for Big Rock and Palisades and are in the process of preparing updated cost estimates.
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Big Rock: In 1997, Big Rock closed permanently and plant decommissioning began. We estimate that the Big Rock site will be returned to a natural state by the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010. The following table shows our Big Rock decommissioning activities:
These activities had no material impact on net income. At December 31, 2003, we have an investment in nuclear decommissioning trust funds of $88 million for Big Rock. In addition, at December 31, 2003, we have charged $7 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.
Palisades: In December 2000, the NRC extended the Palisades operating license to March 2011 and the impact of this extension was included as part of our March 2001 filing with the MPSC.
At December 31, 2003, we have an investment in the MPSC nuclear decommissioning trust funds of $477 million for Palisades. In addition, at December 31, 2003, we have a FERC decommissioning trust fund with a balance of $10 million. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 12, Asset Retirement Obligations.
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 12, Asset Retirement Obligation. 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.
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Property, plant, and equipment at December 31, 2003 and 2002, was as follows:
- ------------------------- (a) Capital leases presented in this table are gross amounts. Amortization of capital leases was $38 million in 2003 and $96 million in 2002.
(b) Includes unrecoverable base natural gas in underground storage of $23 million at December 31, 2003 and $23 million at December 31, 2002, which is not subject to depreciation.
(c) Included in construction costs at December 31, 2002 was $54 million, relating to the capital lease of our main headquarters. We purchased the main headquarters in November 2003.
(d) Included in net property, plant and equipment are intangible assets primarily related to software development costs, consents, and rights of way. The estimated amortization life for software development costs is seven years and other intangible amortization lives range from 50 to 75 years. Intangible assets at December 31, 2003 and 2002, were as follows:
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(e) The following table illustrates the depreciable life for electric and gas structures and improvements.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for comparative purposes. These reclassifications did not affect consolidated net income for the years presented.
RELATED PARTY TRANSACTIONS: We received income from related parties as follows:
We sell, store, and transport natural gas, as well as provide various other services to the MCV Partnership. For additional details on transactions with the MCV Partnership and the FMLP, see Note 2, Uncertainties, "Other Electric Uncertainties -- The Midland Cogeneration Venture," and Note 11, Summarized Financial Information of Significant Related Energy Supplier.
We issued Trust Preferred Securities through several Consumers' affiliated companies. As of December 31, 2003, we deconsolidated the trusts that hold the mandatorily redeemable Trust Preferred Securities. As a result of the deconsolidation, we now record on the Consolidated Statements of Income interest on long-term debt -- related parties to the trusts holding the Trust Preferred Securities. For additional information on Consumers' affiliated Trust Preferred Securities companies, see Note 3, Financings and Capitalization, "Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries" and Note 13, Implementation of New Accounting Standards.
We own 2.4 million shares of CMS Energy Common Stock with a fair value of $20 million at December 31, 2003. For additional details on our investment in CMS Energy Common Stock, see Note 4, Financial and Derivative Instruments.
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We recorded expense from related parties as follows:
We pay overhead costs to CMS Energy based on accepted industry allocation methodologies, such as the Massachusetts Formula. We base our other related party transactions on regulated prices, market prices, or competitive bidding.
TRADE RECEIVABLES: We record our accounts receivable at fair value. Accounts deemed uncollectable are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We amortize premiums, discounts, and expenses incurred in connection with the issuance of outstanding long-term debt over the terms of the issues. For the regulated portions of our businesses, if debt is refinanced, we amortize any unamortized premiums, discounts, and expenses over the term of the new debt.
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.
In 1999, we received MPSC electric restructuring orders, which, among other things, identified the terms and timing for implementing electric restructuring in Michigan. Consistent with these orders and EITF No. 97-4, we discontinued the application of SFAS No. 71 for the energy supply portion of our business because we expected to implement ROA at competitive market based rates for our electric customers.
Since 1999, there have been significant legislative and regulatory changes in Michigan that has resulted in:
- electric supply customers of utilities remaining on cost-based rates, and
- utilities being provided the opportunity to recover Stranded Costs associated with electric restructuring, from customers who choose an alternative electric supplier.
During 2002, we re-evaluated the criteria used to determine if an entity or a segment of an entity meets the requirements to apply regulated utility accounting, and determined that the energy supply portion of our business could meet the criteria if certain regulatory events occurred. In December 2002, we received a MPSC Stranded Cost order that allowed us to re-apply regulatory accounting standard SFAS No. 71 to the energy supply portion of our business. Re-application of SFAS No. 71 had no effect on the prior discontinuation accounting, but allowed us to apply regulatory accounting treatment to the energy supply portion of our business beginning in the fourth quarter of 2002, including regulatory accounting treatment of costs required to be recognized in accordance with SFAS No. 143. For additional details, see Note 12, Asset Retirement Obligations.
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.
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The following regulatory assets and liabilities, which include both current and non-current amounts, are reflected in the Consolidated Balance Sheets. We expect to recover these costs through rates over periods of up to 14 years. We recognized an OPEB transition obligation in accordance with SFAS No. 106 and established a regulatory asset for this amount that we expect to recover in rates over the next nine years.
In October 2000, we received an MPSC order authorizing us to securitize certain regulatory assets up to $469 million, net of tax, see Note 2, Uncertainties, "Electric Restructuring Matters-Securitization." Accordingly, in December 2000, we established a regulatory asset for securitized costs of $709 million, before tax, that had previously been recorded in other regulatory asset accounts. To prepare for the financing of the securitized assets and the subsequent retirement of debt with Securitization proceeds, issuance fees were capitalized as a part of Securitization costs. These issuance costs are amortized each month for up to fourteen years. The components of the unamortized securitized costs are illustrated below.
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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 conclusions about the causes of the August 14, 2003 blackout, including exposure to liability, increased regulatory requirements, and new legislation,
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to purchased power price increases,
- responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel,
- potential adverse appliance service plan ruling or related legislation,
- 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 litigation and government investigations.
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 CE-43
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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 other investigations concerning round-trip trading, including an investigation by the SEC regarding round-trip trades and CMS Energy's financial statements, accounting policies and controls, and an investigation by the United States Department of Justice. CMS Energy is unable to predict the outcome of these matters, and what effect, if any, these investigations will have on its business.
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. 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. 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. It submitted these rules to the EPA for approval in the first quarter of 2003. The EPA has yet to approve the Michigan rules. If the EPA does not approve the Michigan rules, 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 December 31, 2003, we have incurred $446 million in capital expenditures to comply with the EPA regulations and anticipate that the remaining $325 million of capital expenditures will be incurred 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 a 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
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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.
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.
Future clean air regulations requiring emission controls for sulfur dioxide, nitrogen oxides, mercury, and nickel may require additional capital expenditures. Total expenditures will depend upon the final makeup of the new regulations.
Water: The EPA has proposed changes to the rules that govern generating plant cooling water intake systems. The proposed rules will require significant reduction in fish killed by operating equipment. The proposed rules are scheduled to become final in the first quarter of 2004 and some of our facilities would be required to comply by 2006. We are studying the proposed 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 December 31, 2003, 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 in regard to the PSCR plan case. In February 2004, the judge ruled on the motion and deferred to the primary jurisdiction of the MPSC. This ruling effectively suspends the lawsuit until the MPSC rules. 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.
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ELECTRIC RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, the Michigan legislature passed electric utility restructuring legislation known as the Customer Choice Act. This act:
- allows all customers to choose their electric generation supplier effective January 1, 2002,
- provides 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,
- 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. The MPSC found that once the planned projects were completed and verification was submitted, a utility was in technical compliance. 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 PLAN: In 1998, we submitted a plan for electric ROA to the MPSC. In March 1999, the MPSC issued orders generally supporting the plan. The Customer Choice Act states that the MPSC orders issued before June 2000 are in compliance with this act and enforceable by the MPSC. Those MPSC orders:
- allow electric customers to choose their supplier,
- authorize recovery of net Stranded Costs from ROA customers and implementation costs from all customer classes, and
- confirm any voluntary commitments of electric utilities.
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
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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 March 2004, alternative electric suppliers are providing 735 MW of load. This amount represents nine percent of the total distribution load and an increase of 42 percent compared to March 2003.
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. 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 of approximately 0.4 cent per kWh to ROA customers and eliminates securitization offsets of 0.7 cents per kWh for primary service customers and 0.9 cents per kWh for secondary service customers. We are seeking similar recovery of Stranded Costs due to ROA customers leaving our system and are encouraged by this ruling.
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 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 prior to 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, $50 million for the twelve months ended December 31, 2003, and $52 million for the twelve months ended December 31, 2002, 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. The MPSC rejected the portion of the application related to pension costs. The MPSC based
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its decision on the reasoning that a rebounding economy and stock market could potentially reverse recent Pension Plan losses. Also, the MPSC rejected Palisades expenditures previously not securitized as eligible securitized costs; therefore, these costs will be included in a future electric rate case proceeding with the MPSC and as a component of the 2002 net Stranded Cost calculation. 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 financing order will become effective after acceptance by us and 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.
We are authorized by the MPSC 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 and 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 in 2002, and for approval of a net Stranded Cost recovery charge. Our net Stranded Costs incurred in 2002 are estimated to be $38 million with the issuance of Securitization bonds that include Clean Air Act investments, or $85 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. We cannot predict how the MPSC will rule on our request for the recoverability of Stranded Costs.
Implementation Costs: Since 1997, we have incurred significant electric utility restructuring 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.
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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 December 31, 2003, $2 million of additional implementation costs and $19 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. Cash recovery from customers is expected to begin after the rate cap period expires. The rate cap expired for large commercial and industrial customers on December 31, 2003. We have asked to include implementation costs through December 31, 2000 in the pending Securitization case. If approved, the sale of Securitization bonds will allow for the recovery of a significant portion of these costs. We cannot predict the amount the MPSC will approve as allowable costs.
Also, we are pursuing authorization at the FERC for 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. In May 2003, the FERC issued an order denying MISO's request for authorization to reimburse us. In June 2003, we filed a joint petition with MISO for rehearing with the FERC, which the FERC denied in September 2003. We appealed the FERC ruling at the United States Court of Appeals for the District of Columbia and are pursuing other potential means of recovery at the FERC. In conjunction with our appeal of the September order denying recovery, MISO agreed to file a request with the FERC seeking authority to reimburse METC. As part of the contract for the sale of our former transmission system, should the FERC approve the new MISO filing, METC is contractually obligated to flow-through to us the full amount of any Alliance RTO start-up costs that it is authorized to recover by FERC. We cannot predict the outcome of the appeal process, the MISO request, or the ultimate amount, if any, FERC will allow us to collect for implementation 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 impact 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, transmission rates charged to us are fixed by contract at current levels through December 31, 2005, and are subject to FERC ratemaking thereafter. However, we are subject to certain additional MISO surcharges, which are estimated to be $15 million in 2004.
ELECTRIC RATE MATTERS
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 CE-49
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businesses. Approximately 100,000 of our 1.7 million electric customers were without power for approximately 24 hours as a result of the disturbance. We incurred $1 million of immediate expense as a result of the blackout. We continue to cooperate with investigations of the blackout by several federal and state agencies. We cannot predict the outcome of these investigations.
In November 2003, the MPSC released its report on the blackout. The MPSC report found no evidence to suggest that the events in Michigan or actions taken by the Michigan utilities or transmission operators were factors contributing to the cause of the blackout. Also in November 2003, the United States and Canadian power system outage task force preliminarily reported that the primary cause of the blackout was due to transmission line contact with trees in areas outside of Consumers' operating territory. 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. Consumers intends to comply with the MPSC's request.
In February 2004, the Board of Trustees of NERC approved recommendations to improve electric transmission reliability. The key recommendations are as follows:
- strengthen the NERC compliance enforcement program,
- evaluate vegetation management procedures, and
- improve technology to prevent or mitigate future blackouts.
These recommendations require transmission operators, which Consumers is not, to submit annual reports on vegetation management beginning March 2005 and improve technology over various milestones throughout 2004. These recommendations could result in increased transmission costs payable by transmission customers in the future. The financial impacts of these recommendations are not currently quantifiable.
PERFORMANCE STANDARDS: Electric distribution performance standards developed by the MPSC were in proposal status during 2002 and 2003. The performance standards were placed into Michigan law in January 2004 and became effective on February 9, 2004. They relate to restoration after an outage, safety, and customer relations. During 2002 and 2003, Consumers monitored and reported to the MPSC its 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 value of such incentive cannot be determined at this point as the performance standards do not contain an approved incentive mechanism. Financial penalties in the form of customer credits are also possible. These customer credits are based on duration and repetition of outages. We cannot predict the likely effects of the financial incentive or penalties, if any, on us.
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 option 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 December 31, 2003, 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 $20 million for unexpired capacity and energy contracts. Currently, we have a reserve margin of 5 percent, or supply resources equal to 105 percent of projected summer peak load for summer 2004. We are in the process of securing the additional capacity needed to meet our summer 2004 reserve margin target of 11 percent (111 percent of projected summer
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peak load). The total premium costs of electricity call option and capacity and energy contracts for 2003 were approximately $10 million.
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 cap, 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 MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the MCV Partnership, and
- CMS Holdings holds, through FMLP, a 35 percent lessor interest in the MCV Facility.
Our consolidated retained earnings include undistributed earnings from the MCV Partnership, which at December 31, 2003 are $245 million and at December 31, 2002 are $226 million.
Summarized Statements of Income for CMS Midland and CMS Holdings
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.
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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 MPSC cost-recovery orders. The remaining liability associated with the loss totaled $27 million at December 31, 2003, $53 million at December 31, 2002, and $77 million at December 31, 2001. 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:
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 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 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 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 our equity interest in the MCV Partnership may be affected negatively.
Under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and 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 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 exercise 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 equity interest in the MCV Partnership.
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In February 2004, we filed a resource conservation plan with the MPSC that is intended to help conserve natural gas and thereby improve our equity investment in the MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility on an economic basis depending 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. We requested that the MPSC provide interim approval while it conducts a full review of the plan. The MPSC has scheduled a prehearing conference with respect to the MCV resource conservation plan for April 2004. We cannot predict if or when the MPSC will approve our request.
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 our recovery of capacity payments. Natural gas prices have been historically volatile. 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. Therefore, we cannot predict the impact of these issues on our future earnings, cash flows, or on the value of our equity interest in the MCV Partnership.
NUCLEAR MATTERS: Big Rock: Significant progress continues to be made in the decommissioning of Big Rock. We submitted the License Termination Plan to the NRC staff for review in April 2003. System dismantlement and building demolition are on schedule to return the 560-acre site to a natural setting for unrestricted use in early 2006. The NRC and Michigan Department of Environmental Quality continue to find that all decommissioning activities at Big Rock are being performed in accordance with applicable regulatory and license requirements.
Seven transportable dry casks have been loaded with spent nuclear fuel and an eighth cask has been loaded with high-level radioactive waste material. These dry casks will remain onsite until the DOE moves the material to a national spent nuclear fuel repository.
Palisades: In July 2003, the NRC completed its mid-cycle plant performance assessment of Palisades. The mid-cycle assessment for Palisades covered the period from January 1, 2003 through the end of July 2003. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. Based on the plant's performance, only regularly scheduled inspections are planned through September 2004.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of December 31, 2003, we have loaded 18 dry casks with spent nuclear fuel and we will need to load additional dry casks by the fall of 2004 in order to continue operation. Palisades currently has three empty dry casks onsite, with storage pad capacity for up to seven additional loaded dry casks. We anticipate that transportable dry casks, along with more storage pad capacity, will be available by fall 2004.
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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 storage and disposal should be placed in an independent trust. The complaint also asks the MPSC to take additional actions. In May 2003, Consumers and other named utilities each filed motions to dismiss the complaint. We are unable to predict the outcome of this matter.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL, totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $26 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 $10.862 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.
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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 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 from 2004 to 2005, and total an estimated $177 million. Our coal transportation contracts expire from 2004 to 2007, and total an estimated $139 million. Long-term coal supply contracts account for approximately 60 to 90 percent of our annual coal requirements. In 2003, coal purchases totaled $265 million of which $207 million (78 percent of the tonnage requirement) was under long-term contract. We supplement our long-term contracts with spot-market purchases.
Power Supply, Capacity, and Transmission: As of December 31, 2003, we had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2004 and 2005 totaling $8 million. We also had commitments to purchase capacity and energy under long-term power purchase agreements with various generating plants including the MCV Facility. These contracts require monthly capacity payments based on the plants' availability or deliverability. These payments for 2004 through 2030 total an estimated $16.016 billion, undiscounted, which includes $11.381 billion related to the MCV Facility. 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.
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 MPSC approved rates charged to our customers. As of December 31, 2003, we have recorded a liability of $44 million, net of $38 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.
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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 February 2004, the parties in the case reached a tentative settlement agreement that would result in a GCR disallowance of $11 million for the GCR period. Interest on the disallowed amount from April 1, 2003 through February 2004, at the Consumers' authorized rate of return, adds $1 million to the cost of the settlement. We believe this settlement agreement will be executed by the parties in the case in the near future and approved by the MPSC. A reserve was recorded in December 2003.
In July 2003, the MPSC approved a settlement agreement authorizing us to increase our gas cost recovery for the remainder of the current GCR plan year (August 2003 through March 2004) and to apply a quarterly ceiling price adjustment, based on a formula that tracks changes in NYMEX natural gas prices. The terms of the settlement allow a GCR ceiling price of $6.11 per mcf. Our GCR is $5.36 per mcf for March 2004 bills.
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. The MPSC is not bound by these recommendations and will consider the issues anew after receipt of exceptions and replies to the exception filed by the parties in response to the Proposal for Decision.
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 independent of the 2003 gas rate case. 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.
OTHER GAS UNCERTAINTIES
COMMITMENTS FOR GAS SUPPLIES: We enter into contracts to purchase gas and gas transportation from various suppliers for our natural gas business. These contracts have expiration dates that range from 2004 to 2007. Our 2003 gas purchases totaled 248 bcf at a cost of $1.379 billion. At the end of 2003, we estimate our gas purchases for 2004 to be 235 bcf, of which 22 percent is covered by existing fixed price contracts and 37 percent is covered by indexed price contracts that are subject to price variations. The remaining 2004 gas purchases will be made at market prices at the time of purchase.
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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.
3: FINANCINGS AND CAPITALIZATION
LONG-TERM DEBT:
Long-term debt as of December 31 follows:
- ------------------------- (a) 2018 maturity is subject to successful remarketing after June 15, 2005.
(b) Callable at par.
(c) Represents the weighted average interest rate at December 31, 2003.
(d) Maturity date uncertain.
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LONG-TERM DEBT -- RELATED PARTIES:
Long-term debt -- related parties as of December 31, 2003 follows:
NOTES PAYABLE -- RELATED PARTIES: Consumers issued a $200 million unsecured promissory note to CMS Energy on December 30, 2003. The proceeds were used to pay a portion of Consumers' Pension Plan contribution of $329 million in December 2003. This note matures on December 29, 2004 and is payable on three business days' notice by CMS Energy.
DEBT ISSUANCES: The following is a summary of our long-term debt issuances during 2003:
- ------------------------- (bps -- basis points), (GCP -- General corporate purposes)
(a) We filed a registration statement with the SEC in December 2003 to permit holders of these FMBs to exchange their bonds for FMBs that are registered under the Securities Act of 1933. The exchange offer was completed on February 13, 2004.
(b) We used the net proceeds to pay off a $150 million term loan, to pay off a $50 million balance on a term loan that was due to mature in July 2004, and for general corporate purposes.
(c) We used the net proceeds to fund the maturity of a $250 million bond, to fund a $32 million option call payment, and for general corporate purposes.
(d) We used the net proceeds to prepay a portion of a term loan that was due to mature in July 2004.
(e) We used the net proceeds to purchase the headquarters building and pay off the capital lease.
(f) Refer to "Regulatory Authorization for Financings" within this note for details about our remaining FERC debt authorization.
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DEBT MATURITIES: The aggregate annual maturities for long-term debt for the next five years are:
PREFERRED STOCK: The following table describes our Preferred Stock outstanding:
REGULATORY AUTHORIZATION FOR FINANCINGS: At December 31, 2003, 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 December 31, 2003, 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 other long-term securities.
With the granting of authorization, FERC waived its competitive bid/negotiated placement requirements applicable to the long-term securities authorization. The authorizations expire on June 30, 2004.
SHORT-TERM FINANCINGS: We have a $400 million revolving credit facility with banks. The facility is secured with first mortgage bonds. The interest rate of the facility is LIBOR plus 175 basis points. This facility expires in March 2004 with two annual extensions at our option, which would extend the maturity to March 2006. At December 31, 2003, $390 million is available for general corporate purposes, working capital, and letters of credit.
At December 31, 2002, $457 million of bank notes were outstanding at a weighted average interest rate of 4.50 percent.
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.
POLLUTION CONTROL REVENUE BONDS: In January 2004, we amended the PCRB indentures to add an auction rate interest mode and switched to that mode for the two floating rate bonds. Under the auction rate mode, the bonds' interest rate will be reset every 35 days. While in the auction rate mode, no letter of credit liquidity facility is required and investors do not have a put right.
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARIES: We formed various statutory wholly owned business trusts for the sole purpose of issuing preferred securities and lending the gross
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proceeds to ourselves. The sole assets of the trusts are debentures with terms similar to those of the preferred security. Summarized information for mandatorily redeemable preferred securities is as follows:
- ------------------------- (a) We determined that we do not hold the controlling financial interest in 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 and are reflected in Long-term debt -- related parties. For additional details, refer to "Long-Term Debt -- Related Parties" within this Note and Note 13, Implementation of New Accounting Standards.
(b) The trusts must redeem the securities at a liquidation value of $25 per share, which is equivalent to the carrying cost plus accrued but unpaid distributions, when the securities are paid at maturity or upon any earlier redemption. Prior to an early redemption date, the securities could be redeemed at market value.
Each trust receives payments on the debenture it holds. Those receipts are used to make cash distributions on the preferred securities the trust has issued.
The securities allow us the right to defer interest payments on the debentures, and, as a consequence, the trusts will defer dividend payments on the preferred securities. Should we exercise this right, we cannot declare or pay dividends on, or redeem, purchase or acquire, any of our capital stock during the deferral period until all deferred dividends are paid in full.
In the event of default, holders of the preferred securities will be entitled to exercise and enforce the trusts' creditor rights against us, which may include acceleration of the principal amount due on the debentures. We have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debentures, related indenture and trust documents, provide full and unconditional guarantees for the trusts' obligations under the preferred securities.
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. The amounts sold were $297 million at December 31, 2003 and $325 million at December 31, 2002. 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.
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Certain cash flows received from and paid to us under our accounts receivable sales program are shown below:
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at December 31, 2003, we had $373 million of unrestricted retained earnings available to pay common dividends. However, covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. Through December 31, 2003, we made the following common stock dividend payments:
As of December 18, 2003, we are also under an annual dividend cap of $190 million imposed by the MPSC during the current interim gas rate relief period. Because all of the $218 million of common stock dividends to CMS Energy were paid prior to December 18, 2003, we were not out of compliance with this new restriction for 2003. In February 2004, we paid a $78 million common stock dividend.
For additional details on the potential cap on common dividends payable included in the MPSC Securitization order, see Note 2, Uncertainties, "Electric Restructuring Matters -- Securitization." Also, 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."
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.
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The following tables describe our guarantees at December 31, 2003:
- ------------------------- (a) Recourse provision indicates the approximate recovery from third parties including assets held as collateral.
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 investments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar investments or other valuation techniques. The carrying amount of all long-term financial instruments, except as shown below, approximate fair value. For additional details, see Note 1, Corporate Structure and Accounting Policies.
- ------------------------- (a) Settlement of long-term debt is generally not expected until maturity.
(b) We determined that we do not hold the controlling financial interest in 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 and are reflected in Long-term debt -- related parties on the Consolidated Balance Sheets. For additional details, see Note 3, Financings and Capitalization, "Long-Term Debt -- Related Parties" and Note 13, Implementation of New Accounting Standards.
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(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 December 31, 2003, 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) 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. Derivative accounting is required for certain contracts used to limit our exposure to electricity and gas commodity price risk and interest rate risk.
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The following table reflects the fair value of all contracts requiring derivative accounting:
The fair value of all derivative contracts, except the fair value of derivative contracts associated with our equity investment in the MCV Partnership, is included in either Other Assets or Other Liabilities on the Consolidated Balance Sheets. The fair value of derivative contracts associated with our equity investment in the MCV Partnership is included in Investments -- Midland Cogeneration Venture Limited Partnership on the Consolidated Balance Sheets. Effective April 1, 2002, the MCV Partnership changed its accounting for derivatives. For additional details see Note 11, Summarized Financial Information of Significant Related Energy Supplier.
Cumulative Effect of Change in Accounting Principle: On January 1, 2001, upon initial adoption of the derivatives standard, we recorded a $21 million, net of tax, cumulative effect transition adjustment as an unrealized gain increasing accumulated other comprehensive income. In June and December 2001, the FASB issued guidance that resolved the accounting for certain utility industry contracts. As a result, we recorded a $3 million, net of tax, cumulative effect adjustment as an unrealized loss, decreasing accumulated other comprehensive income, and on December 31, 2001, recorded an $11 million, net of tax, cumulative effect adjustment as a decrease to earnings. These adjustments relate to the difference between the fair value and the recorded book value of certain electric call option contracts.
ELECTRIC CONTRACTS: Our electric 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.
Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan, as defined by SFAS No. 133, and the 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 a 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, particularly related to the PPA, could be material to the financial statements.
Our electric business also uses gas option and swap contracts to protect against price risk due to the fluctuations in the market price of gas used as fuel for generation of electricity. These contracts are financial contracts that are used to offset increases in the price of potential gas purchases. These contracts do not qualify for hedge accounting. Therefore, we record any change in the fair value of these contracts directly in earnings as part of power supply costs.
For the year ended December 31, 2003, the unrealized gain in accumulated other comprehensive income related to our proportionate share of the effects of derivative accounting related to our equity investment in the MCV Partnership is $10 million, net of tax. We expect to reclassify this gain, if this value remains, as an increase to earnings from equity method investees during the next 12 months.
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GAS CONTRACTS: Our gas utility business uses fixed price 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.
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 December 31, 2003, we did not have any interest rate swaps outstanding. As of December 31, 2002, 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 all interest rate hedges; therefore, there was no ineffectiveness associated with these hedges.
5: INCOME TAXES
We file a consolidated federal income tax return with CMS Energy. Income taxes are generally allocated based on each company's separate taxable income. We had tax related receivables from CMS Energy of $46 million in 2003 and $44 million in 2002.
The Job Creation and Worker Assistance Act of 2002 provided corporate taxpayers a 5-year carryback of tax losses incurred in 2001 and 2002. As a result of this legislation, CMS Energy was able to carry back consolidated 2001 and 2002 tax losses to tax years 1996 through 1999 to obtain refunds of prior years tax payments totaling $250 million. The tax loss carryback, however, resulted in a reduction in AMT credit carryforwards that previously had been recorded by CMS Energy as deferred tax assets in the amount of $47 million. This non-cash reduction in AMT credit carryforwards was reflected in the 2002 tax provision of CMS Energy and allocated to each of its consolidated subsidiaries under the CMS Energy tax sharing agreement. Consumers' allocable share, $25 million, was reflected in 2002 as a dividend paid by us to CMS Energy.
We practice deferred tax accounting for temporary differences in accordance with SFAS No. 109. We use ITC to reduce current income taxes payable, and defer and amortize ITC over the life of the related property. AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2003, we had AMT credit carryforwards in the amount of $11 million that do not expire, and tax loss carryforwards in the amount of $71 million that expire in 2021 and 2022.
The significant components of income tax expense (benefit) consisted of:
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The principal components of our deferred tax assets (liabilities) recognized in the balance sheet are as follows:
The actual income tax expense differs from the amount computed by applying the statutory federal tax rate of 35 percent to income before income taxes as follows:
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6: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan to key management employees based on their contributions to the successful management of the company. The Plan includes the following type of awards for common stock:
- restricted shares of common stock,
- stock options, and
- stock appreciation rights.
Restricted shares of CMS Energy Common Stock are outstanding shares with full voting and dividend rights. These awards vest over five years at the rate of 25 percent per year after two years. Some restricted shares are subject to achievement of specified levels of total shareholder return and are subject to forfeiture if employment terminates before vesting. Restricted shares vest fully if control of CMS Energy changes.
Stock options give the holder the right to purchase common stock at a given price over an extended period of time. Stock appreciation rights give the holder the right to receive common stock appreciation, which is defined as the excess of the market price of the stock at the date of exercise over the grant date price. CMS Energy stock options and stock appreciation rights are valued at market price when granted. All options and rights may be exercised upon grant and they expire up to ten years and one month from the date of grant.
Our Performance Incentive Stock Plan was amended in January 1999. It uses the following formula to grant awards:
- up to five percent of CMS Energy Common Stock outstanding at January 1 each year less:
- the number of shares of restricted common stock awarded, and
- Common Stock subject to options granted under the plan during the immediately preceding four calendar years.
- the number of shares of restricted CMS Energy Common Stock awarded under this plan cannot exceed 20 percent of the aggregate number of shares reserved for award, and
- forfeiture of shares previously awarded will increase the number of shares available to be awarded under the plan.
Awards of up to 2,240,247 shares of CMS Energy Common Stock may be issued as of December 31, 2003.
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The following table summarizes the restricted stock and stock options granted to our key employees under the Performance Incentive Stock Plan:
At December 31, 2003, 70,567 of the 662,547 shares of CMS Energy restricted common stock outstanding are subject to performance objectives. Compensation expense for restricted stock was $4 million in 2003, less than $1 million in 2002, and $3 million in 2001.
The following table summarizes our stock options outstanding at December 31, 2003:
In December 2002, we adopted the fair value based method of accounting for stock-based employee compensation, under SFAS No. 123, as amended by SFAS No. 148. We elected to adopt the prospective method recognition provisions of this Statement, which applies the recognition provisions to all awards granted, modified, or settled after the beginning of the fiscal year that the recognition provisions are first applied.
The following table summarizes the weighted average fair value of stock options granted:
- ------------------------- (a) For 2002, there were two stock option grants.
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The stock options fair value is estimated using the Black-Scholes model, a mathematical formula used to value options traded on securities exchanges. The following assumptions were used in the Black-Scholes model:
- ------------------------- (a) For 2002, there were two stock option grants.
We recorded $3 million as stock-based employee compensation cost for 2003, and $1 million for 2002. If stock-based compensation costs had been determined under SFAS No. 123 for the year ended December 31, 2001, consolidated net income and pro forma net income would have been as follows:
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 Panhandle. The Pension Plan's assets are not distinguishable by company.
In June 2003, CMS Energy sold Panhandle to Southern Union Panhandle Corp. No portion of the Pension Plan assets were transferred with the sale and Panhandle employees are no longer eligible to accrue additional benefits. The Pension Plan retained pension payment obligations for Panhandle employees that were vested under the Pension Plan.
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The sale of Panhandle resulted in a significant change in the makeup of the Pension Plan. A remeasurement of the obligation was required at the date of sale. The remeasurement further resulted in the following:
- an increase in OPEB expense of $4 million for 2003, and
- an additional charge to accumulated other comprehensive income of $31 million ($20 million after-tax) because of the increase in the additional minimum pension liability. Due to large contributions, the additional minimum pension liability was eliminated as of December 31, 2003.
In 2003, a substantial number of retiring employees elected a lump sum payment instead of receiving pension benefits as an annuity over time. Lump sum payments constitute a settlement under SFAS No. 88. A settlement loss must be recognized when the cost of all settlements paid during the year exceeds the sum of the service and interest costs for that year. We recorded a settlement loss of $48 million ($31 million after-tax) in December 2003.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code; SERP trust earnings are taxable and trust assets are included in consolidated assets. Trust assets were $22 million at December 31, 2003, and $19 million at December 31, 2002. The assets are classified as other non-current assets. The Accumulated Benefit Obligation for SERP was $19 million at December 31, 2003 and $17 million at December 31, 2002.
OPEB: Retiree health care costs at December 31, 2003 are based on the assumption that costs would increase 8.5 percent in 2003. The rate of increase is expected to be 7.5 percent for 2004. The rate of increase is expected to slow to an estimated 5.5 percent by 2010 and thereafter.
The health care cost trend rate assumption significantly affects the estimated costs recorded. A one-percentage point change in the assumed health care cost trend assumption would have the following effects:
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.
EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premium for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. As of December 31, 2003, the Accumulated Benefit Obligation of the EISP was $3 million. Consumers' portion of the EISP was $300,000.
The measurement date for all plans is December 31.
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Assumptions: The following table recaps the weighted-average assumptions used in our retirement benefits plans to determine the benefit obligation and net periodic benefit cost:
- ------------------------- (a) We determine our long-term rate of return by considering historical market returns, the current and future economic environment, the capital market principals of risk and return, and the expertise of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed periodically for reasonability and appropriateness.
Costs: The following table recaps the costs incurred in our retirement benefits plans:
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
- ------------------------- (a) At December 31, 2003, there were 4,970,000 shares of CMS Energy Common Stock in the Pension Plan assets with a fair value of $42 million, and 414,000 shares in the OPEB plan assets, with a fair value of CE-71
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$4 million. At December 31, 2002, there were 5,099,000 shares of CMS Energy Common Stock in the Pension Plan assets with a fair value of $48 million, and 284,000 shares in the OPEB plan assets, with a fair value of $3 million.
(b) At February 29, 2004, the Pension Plan assets were 66 percent equity and 34 percent fixed income. We plan to contribute $71 million to our OPEB plan in 2004. We estimate a contribution of $23 million to our Pension Plan in 2004.
We have established a target asset allocation for our Pension Plan assets of 65 percent equity and 35 percent fixed income investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor's 500 Index, with a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a Foreign Equity Index Fund. Fixed income investments are diversified across investment grade instruments of both government and corporate issuers. Annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation.
We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the rate making process for Consumers, and through direct contributions from the non-utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in an Standard & Poor's 500 Index fund. The fixed income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.
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Reconciliations: The following table reconciles the funding of our retirement benefit plans with our retirement benefit plans liability:
- ------------------------- (a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003. This Act 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 have decided to defer recognizing the effects of the Act in our 2003 financial statements, as permitted by FASB Staff Position No. 106-1. When accounting guidance is issued, our retiree health benefit obligation may be adjusted.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.055 billion exceeded the value of the Pension Plan assets and net balance sheet liability at December 31, 2002. As a result, we recorded an additional minimum liability, including an intangible asset of $40 million, and $285 million of accumulated other comprehensive income. In August 2003, we made our planned contribution of $172 million to the Pension Plan. In December 2003, we made an additional contribution of $329 million to the Pension Plan that eliminated the additional minimum liability. The Accumulated Benefit Obligation for the Pension Plan was $1.019 billion at December 31, 2003.
(c) As of December 31, 2003, we have recorded a prepaid pension asset of $384 million, $20 million of which is in other current assets on our consolidated balance sheets.
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8: LEASES
We lease various assets, including vehicles, railcars, construction equipment, furniture, and buildings. We have both full-service and net leases. A net lease requires us to pay for taxes, maintenance, operating costs, and insurance. Most of our leases contain options at the end of the initial lease term to:
- purchase the asset at the then fair value of the asset, or
- renew the lease at the then fair rental value.
Minimum annual rental commitments under our non-cancelable leases at December 31, 2003, were:
We are authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. Operating lease charges were $13 million in 2003, $13 million in 2002, and $15 million in 2001.
Capital lease expenses were $17 million in 2003, $20 million in 2002, and $26 million in 2001. Included in the $26 million for 2001, is $7 million of nuclear fuel lease expense. In November 2001, our nuclear fuel capital leasing arrangement expired. At termination of the lease, we paid the lessor $48 million, which was the lessor's remaining investment at that time.
In April 2001, we entered into a lease agreement for the construction of an office building to be used as the main headquarters for CMS Energy in Jackson, Michigan. In November 2003, we exercised our purchase option under the lease agreement and bought the office building with proceeds from a $60 million term loan.
9: JOINTLY OWNED REGULATED UTILITY FACILITIES
We are required to provide only our share of financing for the jointly owned utility facilities. The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant's undivided
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ownership interest. The following table indicates the extent of our investment in jointly owned regulated utility facilities:
10: 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 tables show 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.
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- ------------------------- (a) 2002 excludes $28 million benefit and 2001 excludes $17 million expense due to the change in accounting for derivative instruments.
(b) 2002 excludes $10 million tax expense and 2001 excludes $6 million tax benefit due to the change in accounting for derivative instruments.
(c) As of December 31, 2003, the trusts that hold the mandatorily redeemable Trust Preferred Securities were deconsolidated. The trusts are now included on the Consolidated Balance Sheets as Investments -- Other.
(d) Amounts include a portion of our other common assets attributable to both the electric and gas utility businesses.
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(e) Amounts include electric restructuring implementation plan, capital leases for nuclear fuel, purchase of nuclear fuel, and other assets. Amounts also include a portion of capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.
11: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER
Under the PPA with the MCV Partnership discussed in Note 2, Uncertainties, our 2003 obligation to purchase electric capacity from the MCV Partnership provided 15 percent of our owned and contracted electric generating capacity. Summarized financial information of the MCV Partnership follows:
STATEMENTS OF INCOME
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BALANCE SHEETS
- ------------------------- (a) Revenue from Consumers totaled $514 million in 2003, $557 million in 2002, and $550 million in 2001.
(b) On April 1, 2002, the MCV Partnership implemented a new accounting standard for derivatives. As a result, the MCV Partnership began accounting for several natural gas contracts containing an option component at fair value. The MCV Partnership recorded a $58 million cumulative effect adjustment for the change in accounting principle as an increase to earnings. CMS Midland's 49 percent ownership share was $28 million ($18 million after-tax), which is reflected as a change in accounting principle on our Consolidated Statements of Income.
(c) Receivables from Consumers totaled $40 million for December 31, 2003 and $44 million for December 31, 2002.
(d) FMLP is the sole beneficiary of a trust that is the lessor in a long-term direct finance lease with the MCV Partnership. CMS Holdings holds a 46.4 percent ownership interest in FMLP. The MCV Partnership's lease obligations, assets, and operating revenues secure FMLP's debt. The following table summarizes obligation and payment information regarding the direct finance lease.
- ------------------------- (e) CMS Midland's recorded investment in the MCV Partnership includes capitalized interest, which we are expensing over the life of our investment in the MCV Partnership. The financing agreements prohibit the MCV Partnership from distributing any cash to its owners until it meets certain financial test requirements. We do not anticipate receiving a cash distribution in the near future.
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12: 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. Accretion of $1 million related to the Big Rock and Palisades' profit component included in the estimated cost of removal was expensed for 2003.
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 be $381 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.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables describe our assets that have legal obligations to be removed at the end of their useful life.
Reclassification of Non-Legal 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 $983 million in 2003 and $907 million in 2002 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 were reclassified as regulatory liabilities in the accompanying consolidated balance sheets.
13: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES: Amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for contracts entered into or modified after June 30, 2003. Implementation of this statement has not impacted our Consolidated Financial Statements.
SFAS NO. 150, ACCOUNTING FOR CERTAIN FINANCIAL INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY: Establishes standards for how we classify and measure certain financial instruments with characteristics of both liabilities and equity. The statement requires us to classify financial instruments within its scope as liabilities rather than mezzanine equity, the area between liabilities and equity. SFAS No. 150 became effective July 1, 2003.
We have four Trust Preferred Securities outstanding as of December 31, 2003 that are issued by our affiliated trusts. Each trust holds a subordinated debenture from the parent company. The terms of the debentures are identical to those of the trust-preferred securities, except that the debenture has an explicit maturity date. The
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
trust documents, in turn, require that the trust be liquidated upon the repayment of the debenture. The preferred securities are redeemable upon the liquidation of the subsidiary; therefore, they are considered equity in the financial statements of the subsidiary.
At their October 29, 2003 Board meeting, the FASB deferred the implementation of the portion of SFAS No. 150 relating to mandatorily redeemable noncontrolling interests in subsidiaries when the noncontrolling interests are classified as equity in the financial statements of the subsidiary. Our Trust Preferred Securities are included in the deferral action.
Upon adoption of FASB Interpretation No. 46, we determined that our trusts that issue Trust Preferred Securities should be deconsolidated and reported as long-term debt -- related parties. Refer to further discussion under "Accounting Standards Not Yet Effective -- FASB Interpretation No. 46, Consolidation of Variable Interest Entities."
EITF ISSUE NO. 01-08, DETERMINING WHETHER AN ARRANGEMENT CONTAINS A LEASE: In May 2003, the EITF reached consensus in EITF Issue No. 01-08 requiring both parties to a transaction, such as power purchase agreements, to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning July 1, 2003.
Prospective accounting under EITF Issue No. 01-08, could affect the timing and classification of revenue and expense recognition. Certain product sales and service revenue and expenses may be required to be reported as rental or leasing income and/or expenses. Transactions deemed to be capital lease arrangements would be included on our balance sheet. The adoption of EITF Issue No. 01-08 has not impacted our results of operations, cash flows, or financial position.
EITF ISSUE NO. 03-04, ACCOUNTING FOR CASH BALANCE PENSION PLANS: In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address the accounting for certain cash balance pension plans. EITF Issue No. 03-04 concluded that certain cash balance plans be accounted for as defined benefit plans under SFAS No. 87, Employers' Accounting for Pensions. The EITF requirements must be applied as of our next plan measurement date after issuance, which is December 31, 2003. In 2003, we started a cash balance pension plan that covers employees hired after June 30, 2003. We account for this plan as a defined benefit plan under SFAS No. 87 and comply with EITF Issue No. 03-04. For further information, see Note 7, Retirement Benefits.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: 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 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 provides an implementation deferral, until the first quarter of 2004. Revised FASB Interpretation No. 46 is effective for the first quarter of 2004 for all entities other than special purpose entities. Special-purpose entities must apply either FASB Interpretation No. 46 or Revised FASB Interpretation No. 46 for the first reporting period that ends after December 15, 2003.
As of December 31, 2003, we have completed our analysis for and have adopted Revised FASB Interpretation No. 46 for all entities other than the MCV Partnership and FMLP. We continue to evaluate and gather information regarding those entities. We will adopt the provisions of Revised FASB Interpretation No. 46 for the MCV Partnership and FMLP in the first quarter of 2004.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
If our completed analysis shows we have the controlling financial interest in the MCV Partnership and FMLP, we would consolidate their assets, liabilities, and activities, including $700 million of non-recourse debt, into our financial statements. Financial covenants under our financing agreements could be impacted negatively after such a consolidation. As a result, it may become necessary to seek amendments to the relevant financing agreements to modify the terms of certain of these covenants to remove the effect of this consolidation, or to refinance the relevant debt. As of December 31, 2003, our investment in the MCV Partnership was $419 million and our investment in the FMLP was $224 million.
We also determined that we do not hold the controlling financial interest in 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 have reflected $506 million of long-term debt -- related parties and have 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.
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 is expected to be presented for FASB clearance in 2004 and would be applicable for fiscal years beginning after December 15, 2004. An asset classified as property, plant, and equipment asset often comprises multiple parts and costs. A component accounting policy determines the level at which those parts are recorded. Capitalization of certain costs related to property, plant, and equipment are included in the total cost. The Statement of Position could impact our component and capitalization accounting for property, plant, and equipment. We continue to evaluate the impact, if any, this Statement of Position will have upon adoption.
14: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
- ------------------------- (a) As of December 31, 2003, we deconsolidated the trusts that hold the mandatorily redeemable Trust Preferred Securities. As a result of the deconsolidation, we now record on the Consolidated Statements of Income interest on long-term debt -- related parties to the trusts holding the Trust Preferred Securities.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- ------------------------- (b) We reclassified $28 million ($18 million after taxes) reducing June and September 2002 operating amounts to reflect the MCV Partnership's change in accounting for derivative instruments as a separate item. For additional details see Note 11, Summarized Financial Information of Significant Related Energy Supplier.
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REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholder Consumers Energy Company
We have audited the accompanying consolidated balance sheets of Consumers Energy Company (a Michigan corporation and wholly-owned subsidiary of CMS Energy Corporation) and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The financial statements of Midland Cogeneration Venture Limited Partnership (a limited partnership in which Consumers Energy Company and subsidiaries has a 49% interest), have been audited by other auditors (the other auditors for 2001 for Midland Cogeneration Venture Limited Partnership have ceased operations) whose reports have been furnished to us; insofar as our opinion on the consolidated financial statements relates to the amounts included for Midland Cogeneration Venture Limited Partnership, it is based solely on their reports.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Consumers Energy Company and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Notes 12 and 13 to the consolidated financial statements, in 2003, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" and of Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities". As discussed in Notes 6 and 11 to the consolidated financial statements, in 2002, the Company adopted the provisions SFAS No. 148, "Accounting for Stock-Based Compensation" and Midland Cogeneration Venture Limited Partnership adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted.
/s/ ERNST & YOUNG LLP
Detroit, Michigan February 27, 2004
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REPORT OF INDEPENDENT AUDITORS
To the Partners and the Management Committee of Midland Cogeneration Venture Limited Partnership:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of the Midland Cogeneration Limited Partnership (a Michigan limited partnership) and its subsidiaries (MCV) at December 31, 2003 and 2002, and the results of their operations and their cash flows for the each of the two years ended December 31, 2003 and 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of MCV's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of MCV for the year ended December 31, 2001, were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated January 18, 2002.
As explained in Note 2 to the financial statements, effective April 1, 2002, Midland Cogeneration Venture Limited Partnership changed its method of accounting for derivative and hedging activities in accordance with Derivative Implementation Group ("DIG") Issue C-16.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan February 18, 2004
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THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ARTHUR ANDERSEN REPORT AND THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners and the Management Committee of the Midland Cogeneration Venture Limited Partnership:
We have audited the accompanying consolidated balance sheets of the MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP (a Michigan limited partnership) and subsidiaries (MCV) as of December 31, 2001 and 2000, and the related consolidated statements of operations, partners' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of MCV's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Midland Cogeneration Venture Limited Partnership and subsidiaries as of December 31, 2001 and 2000, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1, 2001, Midland Cogeneration Venture Limited Partnership changed its method of accounting related to derivatives and hedging activities.
/s/Arthur Andersen LLP
Detroit, Michigan, January 18, 2002
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
CMS ENERGY
In April 2002, CMS Energy's Board of Directors, upon the recommendation of the Audit Committee of the Board, voted to discontinue using Arthur Andersen LLP to audit CMS Energy's financial statements for the year ending December 31, 2002. CMS Energy had previously retained Arthur Andersen LLP to review its financial statements for the quarter ended March 31, 2002. In May 2002, CMS Energy's Board of Directors engaged Ernst & Young LLP to audit its financial statements for the year ending December 31, 2002. Ernst & Young LLP audited 2000, 2001, and 2002. As a result, CMS Energy restated its 2000 and 2001 financial statements. The restated 2001 financial statements are contained herein.
CONSUMERS
In April 2002, Consumers' Board of Directors, upon the recommendation of the Audit Committee of the Board, voted to discontinue using Arthur Andersen LLP to audit Consumers' financial statements for the year ending December 31, 2002. Consumers had previously retained Arthur Andersen LLP to review its financial statements for the quarter ended March 31, 2002. In May 2002, Consumers' Board of Directors engaged Ernst & Young LLP to audit its financial statements for the year ending December 31, 2002. Ernst & Young LLP audited 2000, 2001, and 2002. As a result, Consumers restated its 2000 and 2001 financial statements. The restated 2001 financial statements are contained herein.
ITEM 9A.
ITEM 9A. 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.
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PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.
CMS ENERGY
Information that is required in Item 10 regarding directors and executive officers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 10 regarding Consumers' directors and executive officers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
CMS ENERGY
Information that is required in Item 11 regarding executive compensation is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 11 regarding executive compensation of Consumers' executive officers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT RELATED STOCKHOLDER MATTERS.
CMS ENERGY
Information that is required in Item 12 regarding securities authorized for issuance under equity compensation plans and security ownership of certain beneficial owners and management is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 12 regarding securities authorized for issuance under equity compensation plans and security ownership of certain beneficial owners and management of Consumers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
CMS ENERGY
Information that is required in Item 13 regarding certain relationships and related transactions is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 13 regarding certain relationships and related transactions regarding Consumers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
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ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
CMS ENERGY
Information that is required in Item 14 regarding principal accountant fees and services is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
CONSUMERS
Information that is required in Item 14 regarding Consumers' principal accountant fees and services is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)(1) Financial Statements and Reports of Independent Public Accountants for CMS Energy and Consumers are included in each company's ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA and are incorporated by reference herein.
(a)(2) Financial Statement Schedules and Reports of Independent Public Accountants for CMS Energy and Consumers are included after the Exhibits to the Index to Financial Statement Schedules and are incorporated by reference herein.
(a)(3) Exhibits for CMS Energy and Consumers are listed after Item 15(c) below and are incorporated by reference herein.
(b) Reports on Form 8-K
CMS ENERGY
During the fourth quarter of 2003, CMS Energy filed or furnished the following Current Reports on Form 8-K:
- 8-K filed on October 17, 2003 covering matters pursuant to Item 5, Other Events;
- 8-K filed on October 24, 2003 covering matters pursuant to Item 5, Other Events;
- 8-K furnished on November 12, 2003 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);
- 8-K filed on November 26, 2003 covering matters pursuant to Item 5, Other Events;
- 8-K filed on December 5, 2003 covering matters pursuant to Item 5, Other Events; and
- 8-K filed on December 19, 2003 covering matters pursuant to Item 5, Other Events.
CONSUMERS
During the fourth quarter of 2003, Consumers filed or furnished the following Current Reports on Form 8-K:
- 8-K filed on October 24, 2003 covering matters pursuant to Item 5, Other Events;
- 8-K furnished on November 12, 2003 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);
- 8-K filed on November 26, 2003 covering matters pursuant to Item 5, Other Events;
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- 8-K filed on December 5, 2003 covering matters pursuant to Item 5, Other Events; and
- 8-K filed on December 19, 2003 covering matters pursuant to Item 5, Other Events.
(c) Exhibits, including those incorporated by reference (see also Exhibit volume).
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CMS ENERGY'S AND CONSUMERS' EXHIBITS
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- ------------------------- * Obligations of only CMS Holdings and CMS Midland, second tier subsidiaries of Consumers, and of CMS Energy but not of Consumers.
Exhibits listed above that have heretofore been filed with the Securities and Exchange Commission pursuant to various acts administered by the Commission, and which were designated as noted above, are hereby incorporated herein by reference and made a part hereof with the same effect as if filed herewith.
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INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedules other than those listed above are omitted because they are either not required, not applicable or the required information is shown in the financial statements or notes thereto.
Columns omitted from schedules filed have been omitted because the information is not applicable.
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CMS ENERGY CORPORATION
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
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CONSUMERS ENERGY COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, CMS Energy Corporation has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 11th day of March 2004.
CMS ENERGY CORPORATION
By /s/ KENNETH WHIPPLE ------------------------------------ Kenneth Whipple Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of CMS Energy Corporation and in the capacities and on the 11th day of March 2004.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Consumers Energy Company has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 11th day of March 2004.
CONSUMERS ENERGY COMPANY
By /s/ KENNETH WHIPPLE ------------------------------------ Kenneth Whipple Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of Consumers Energy Company and in the capacities and on the 11th day of March 2004.
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CMS ENERGY'S AND CONSUMERS' EXHIBITS