ITEM 1. BUSINESS.
GENERAL
CMS ENERGY
CMS Energy was formed in Michigan in 1987 and is an energy holding company operating through subsidiaries in the United States and in selected markets around the world. Its two principal subsidiaries are Consumers and Enterprises. Consumers is a public utility that provides natural gas and/or electricity to almost 6.5 million of Michigan's 10 million residents and serves customers in all 68 of the state's Lower Peninsula counties. Enterprises, through various subsidiaries and affiliates, is engaged in diversified energy businesses in the United States and in selected international markets.
CMS Energy's consolidated operating revenue was approximately $5.472 billion in 2004, $5.513 billion in 2003, and $8.673 billion in 2002. CMS Energy operates in three business segments -- electric utility, gas utility, and Enterprises. See BUSINESS SEGMENTS later in this Item 1 for further discussion of each segment.
CONSUMERS
Consumers was formed in Michigan in 1968 and is the successor to a corporation organized in Maine in 1910 that conducted business in Michigan from 1915 to 1968. Consumers' service areas include companies operating in the automotive, metal, chemical and food products industries as well as a diversified group of other industries. In 2004, Consumers served 1.77 million electric customers and 1.69 million gas customers.
Consumers' consolidated operations account for a majority of CMS Energy's total assets and income, as well as a substantial portion of its operating revenue. Consumers' consolidated operating revenue was $4.711 billion in 2004, $4.435 billion in 2003, and $4.169 billion in 2002.
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 owns its principal properties in fee, except that most electric lines and gas mains are located in public roads or on land owned by others and are accessed by Consumers pursuant to easements and other rights. Almost all of Consumers' properties are subject to the lien of its First Mortgage Bond Indenture. For additional information on Consumers' properties see BUSINESS SEGMENTS -- Consumers' Electric Utility Operations -- Electric Utility Properties, and -- Consumers' Gas Utility Operations -- Gas Utility Properties, below.
BUSINESS SEGMENTS
CMS ENERGY FINANCIAL INFORMATION
For further information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to all of CMS Energy's business segments and international and domestic operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION AND CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS AND NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSUMERS FINANCIAL INFORMATION
For further information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to Consumers' electric and gas utility operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION AND CONSUMERS' CONSOLIDATED FINANCIAL STATEMENTS AND NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSUMERS ELECTRIC UTILITY OPERATIONS
ELECTRIC UTILITY OPERATIONS
Consumers' electric utility operating revenue was $2.586 billion in 2004, $2.590 billion in 2003, and $2.648 billion in 2002. Consumers' electric utility operations include the generation, purchase, distribution and sale of electricity. At year-end 2004, it was authorized to provide service in 60 of the 68 counties of Michigan's Lower Peninsula. Principal cities served include Battle Creek, Flint, Grand Rapids, Jackson, Kalamazoo, Midland, Muskegon and Saginaw. Consumers' electric utility customer base includes a mix of residential, commercial and diversified industrial customers, the largest segment of which is the automotive industry. 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 2004, Consumers' electric sales were 36 billion kWh and retail open access deliveries were 4 billion kWh, for total electric deliveries of 40 billion kWh. 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.
Consumers' 2004 summer peak demand was 6,958 MW excluding retail open access loads and 7,643 MW including retail open access loads. For the 2003-04 winter period, Consumers' peak demand was 5,636 MW excluding retail open access loads and 6,076 MW including retail open access loads. In December 2004, Consumers experienced peak demand of 5,750 MW excluding retail open access loads and 6,385 MW including retail open access loads. Based on its summer 2004 forecast, Consumers carried an 11 percent reserve margin target. However, as a result of lower than forecasted peak loads and additional purchases in response to the uncertainty surrounding the Karn 4 exciter failure and eventual replacement, Consumers' ultimate reserve margin was 29.6 percent compared to 14.7 percent in 2003. Currently, Consumers has a reserve margin of approximately 5.4 percent, or supply resources equal to 105.4 percent of projected summer peak load for summer 2005 and is in the process of securing the additional capacity needed to meet its summer 2005 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, 2004, Consumers' electric generating system consisted 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 2004, through long-term purchase contracts, options, spot market and other seasonal purchases, Consumers purchased up to 2,542 MW of net capacity from other power producers (the largest of which was the MCV Partnership), which amounted to 36.6 percent of Consumers' total system requirements.
DISTRIBUTION: Consumers' distribution system includes:
- 356 miles of high-voltage distribution radial lines operating at 120 kilovolts and above;
- 4,178 miles of high-voltage distribution overhead lines operating at 23 kilovolts and 46 kilovolts;
- 17 subsurface miles of high-voltage distribution underground lines operating at 23 kilovolts and 46 kilovolts;
- 55,157 miles of electric distribution overhead lines;
- 8,896 subsurface miles of underground distribution lines; and
- substations having an aggregate transformer capacity of 20,787,500 kilovoltamperes.
Consumers is interconnected to METC, LLC, a member of MISO. METC, LLC is interconnected with neighboring utilities as well as out-state transmission systems.
FUEL SUPPLY: Consumers has four generating plant sites that burn coal. These plants constitute 77.5 percent of Consumers' baseload supply, the capacity used to serve a constant level of customer demand. In 2004, these
plants produced a combined total of 18,810 million kWhs of electricity and burned 9.7 million tons of coal. On December 31, 2004, Consumers had on hand a 31-day supply of coal.
Consumers enters into a number of purchase obligations that represent normal business operating contracts. These contracts are used to assure an adequate supply of goods and services necessary for the operation of its business and to minimize exposure to market price fluctuations. Consumers believes that these future costs are prudent and reasonably assured of recovery in future rates.
Consumers has entered into coal supply contracts with various suppliers and associated rail transportation contracts for its coal-fired generating stations. Under the terms of these agreements, Consumers is obligated to take physical delivery of the coal and make payment based upon the contract terms. Consumers' coal supply contracts expire through 2010, and total an estimated $376 million. Its coal transportation contracts expire through 2009, and total an estimated $205 million. Long-term coal supply contracts have accounted for approximately 60 to 90 percent of Consumers' annual coal requirements over the last 10 years. Although future contract coverage is not finalized at this time, Consumers believes that it will be within the historic 60 to 90 percent range.
As of December 31, 2004, Consumers had future unrecognized commitments to purchase power transmission services under fixed price forward contracts for 2005 totaling $4 million. Consumers also had commitments to purchase capacity and energy under long-term power purchase agreements with various generating plants. These contracts require monthly capacity payments based on the plants' availability or deliverability. These payments for 2005 through 2030 total an estimated $4.503 billion, undiscounted. This amount may vary depending upon plant availability and fuel costs. If a plant were not available to deliver electricity to Consumers, then Consumers would not be obligated to make the capacity payment until the plant could deliver.
Consumers owns Palisades, an operating nuclear power plant located near South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers transferred its authority to operate Palisades to NMC. During 2004, Palisades' net generation was 5,336 million kWhs, constituting 22 percent of Consumers' baseload supply. Palisades' nuclear fuel supply responsibilities are under NMC's control as agent for Consumers. New fuel contracts are being written as NMC agreements. Consumers/NMC currently have sufficient contracts in place to supply 93 percent of the uranium concentrates and conversion services and 100 percent of the enrichment services requirements for the 2006 reload. A contract for conversion services is in place to supply approximately 26 percent of the 2007 reload requirements and a contract for enrichment services is in place to supply approximately 100 percent of the 2007 reload requirements. A mix of spot, medium and long-term contracts are being negotiated with producers and service suppliers who participate in the world nuclear fuel marketplace to provide for the remaining open requirements for the 2007 reload.
Consumers has a contract for nuclear fuel fabrication services in place for the 2006 reload. Contract negotiations are currently ongoing with the current nuclear fuel fabrication vendor to enter into a new contract to cover reloads in 2006 through 2013.
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 2005. Palisades currently has spent nuclear fuel that exceeds its temporary on-site storage pool capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved steel and concrete vaults known as "dry casks." For additional information on disposal of nuclear fuel and Consumers' use of dry casks, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS.
CONSUMERS GAS UTILITY
GAS UTILITY OPERATIONS
Consumers' gas utility operating revenue was $2.081 billion in 2004, $1.845 billion in 2003, and $1.519 billion in 2002. Consumers' gas utility operations purchase, transport, store, distribute and sell natural gas. As of December 31, 2004, it was authorized to provide service in 47 of the 68 counties in Michigan's Lower Peninsula. Principal cities served include Bay City, Flint, Jackson, Kalamazoo, Lansing, Pontiac and Saginaw, as well as the suburban Detroit area, where nearly 900,000 of Consumers' gas customers are located. Consumers' gas utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of such customers is not reasonably likely to have a material adverse effect on its financial condition.
Consumers' gas utility operations are seasonal. Consumers injects natural gas into storage during the summer months for use during the winter months when the demand for natural gas is higher. Peak demand usually occurs in the winter due to colder temperatures and the resulting increased demand for heating fuels. In 2004, 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 389.47 bcf.
GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system consists of:
- 25,756 miles of distribution mains throughout Michigan's Lower Peninsula;
- 1,642 miles of transmission lines throughout Michigan's Lower Peninsula;
- 7 compressor stations with a total of 162,000 installed horsepower; and
- 15 gas storage fields located across Michigan with an aggregate storage capacity of 308 bcf and a working storage capacity of 142.8 bcf.
GAS SUPPLY: In 2004, Consumers purchased 1 percent of the gas it delivered from Michigan producers, 70 percent from United States producers outside Michigan and 22 percent from Canadian producers. Authorized suppliers in the gas customer choice program supplied the remaining 7 percent of gas that Consumers delivered.
Consumers' firm gas transportation agreements are with ANR Pipeline Company, Great Lakes Gas Transmission, L.P., Trunkline Gas Co., Panhandle Eastern Pipe Line Company, and Vector Pipeline. Consumers uses these agreements to deliver gas to Michigan for ultimate deliveries to market. Consumers' firm transportation and city gate arrangements are capable of delivering over 90 percent of Consumers' total gas supply requirements. As of December 31, 2004, Consumers' portfolio of firm transportation from pipelines to Michigan is as follows:
Consumers purchases the balance of its required gas supply under incremental firm transportation contracts, firm city gate contracts, and as needed, interruptible transportation contracts. The amount of interruptible transportation service and its use varies primarily with the price for such service and the availability and price of the spot supplies being purchased and transported. Consumers' use of interruptible transportation is generally in off-peak summer months and after Consumers has fully utilized the services under the firm transportation agreements.
ENTERPRISES
Enterprises, through various subsidiaries, affiliates, and equity investments, is engaged in domestic and international diversified energy businesses including independent power production, natural gas transmission, storage and processing, and energy services. Enterprises' operating revenue was $808 million in 2004, $1.085 billion in 2003, and $4.508 billion in 2002.
NATURAL GAS TRANSMISSION
CMS Gas Transmission was formed in 1988 and owns, develops and manages domestic and international natural gas facilities. In 2004, CMS Gas Transmission's operating revenue was $22 million.
In June 2003, CMS Gas Transmission sold Panhandle to Southern Union Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union Panhandle Corp. purchased all of Panhandle's outstanding capital stock for approximately $582 million in cash and 3.15 million shares of Southern Union common stock. Southern Union Panhandle Corp. also assumed approximately $1.166 billion in debt.
In July 2003, CMS Gas Transmission completed the sale of CMS Field Services to Cantera Natural Gas, Inc. for gross cash proceeds of approximately $113 million, subject to post closing adjustments, and a $50 million face value note of Cantera Natural Gas, Inc. The note is payable to CMS Energy for up to $50 million subject to the financial performance of the Fort Union and Bighorn natural gas gathering systems from 2004 through 2008.
In August 2004, CMS Gas Transmission sold its interest in Goldfields and its Parmelia business, a discontinued operation, to APT for A$204 million (approximately $147 million in U.S. dollars). A $45 million ($29 million after-tax) gain on the sale of Goldfields includes a $9 million ($6 million after-tax) foreign currency translation gain. A $10 million ($6 million after-tax) gain on the sale of Parmelia includes a $3 million ($2 million after-tax) foreign currency translation loss.
NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of 265 miles of gathering and transmission pipelines located in the state of Michigan, with a daily capacity of 0.75 bcf. At December 31, 2004, CMS Gas Transmission had nominal processing capabilities of approximately 0.33 bcf per day of natural gas in Michigan.
At December 31, 2004, CMS Gas Transmission had ownership interests in the following international pipelines:
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 2004, the independent power production business segment's operating revenue was $258 million, which includes revenues from CMS Generation, CMS Operating, S.R.L., the MCV Facility and the MCV Partnership.
INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2004, CMS Generation had ownership interests in operating power plants totaling 8,219 gross MW (3,455 net MW). At December 31, 2004, additional plants totaling approximately 322 gross MW (69 net MW) were under construction or in advanced stages of development. These plants include the Saudi Petrochemical Company power plant, which is under construction in the Kingdom of Saudi Arabia. In 2005, CMS Generation plans to complete the restructuring of its operations by narrowing the scope of its existing operations and commitments to three regions: the U.S., South America, 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 2004 (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. The El Chocon facility is held pursuant to a 30-year possession agreement.
(b) CMS Generation sold its interest in GVK in the first quarter of 2005.
(c) The Jorf Lasfar facility is held pursuant to a right of possession agreement with the Moroccan state-owned Office National de l'Electricite.
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 597 MW natural gas power plant, each in Argentina.
Through CMS Electric and Gas, CMS Enterprises has an 87 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. The MCV Partnership contracted to sell electricity to Consumers for a 35-year period beginning in 1990, and to supply electricity and steam to Dow.
For information on capital expenditures, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- CAPITAL RESOURCES AND LIQUIDITY AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (FINANCINGS AND CAPITALIZATION).
OIL AND GAS EXPLORATION AND PRODUCTION
CMS Energy used to own an oil and gas exploration and production company. In October 2002, CMS Energy completed its exit from the oil and gas exploration and production business.
ENERGY RESOURCE MANAGEMENT
In 2003, CMS ERM closed its Houston, Texas office and in 2004, CMS ERM changed its name from CMS Marketing, Services and Trading Company to CMS Energy Resource Management Company. CMS ERM concentrates on the purchase and sale of energy commodities in support of CMS Energy's generating facilities. In March 2004, CMS ERM discontinued its natural gas retail program as customer contracts expired. In 2004, CMS ERM marketed approximately 53.1 bcf of natural gas and 1,243.5 GWh of electricity. Its operating revenue was $381 million in 2004, $711 million in 2003, and $4.137 billion in 2002.
INTERNATIONAL ENERGY DISTRIBUTION
In October 2001, CMS Energy discontinued the operations of its international energy distribution business. In 2002, CMS Energy discontinued new development outside North America, which included closing all non-U.S. development offices. In 2003, due to the uncertainty of executing an asset sale on acceptable terms and conditions, CMS Energy reclassified to continuing operations SENECA, which is its energy distribution business in Venezuela, and CPEE, which is its energy distribution business in Brazil, and restated the prior year's earnings for these businesses.
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, most significant MPSC orders affecting Consumers have 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 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING.
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 were eligible to select an alternative gas commodity supplier. Consumers' current GCR mechanism allows it to recover from its customers all prudently incurred costs to purchase natural gas commodity and transport it to Consumers' facilities. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- CONSUMERS' GAS UTILITY RATE MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- 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 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS -- NUCLEAR PLANT DECOMMISSIONING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 (CONTINGENCIES) OF CONSUMERS' CONSOLIDATED FINANCIAL STATEMENTS -- NUCLEAR PLANT DECOMMISSIONING.
OTHER REGULATION
The Secretary of Energy regulates the importation and exportation of natural gas and has delegated various aspects of this jurisdiction to 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.
Consumers' electric generating plants must comply with rules that significantly reduce the number of fish killed by plant cooling water intake systems. Consumers is studying options to determine the most cost-effective solutions for compliance.
Like most electric utilities, Consumers has PCB in some of its electrical equipment. During routine maintenance activities, Consumers identified PCB as a component in certain paint, grout and sealant materials at the Ludington Pumped Storage facility. Consumers removed and replaced part of the PCB material. Consumers has proposed a plan to the EPA to deal with the remaining materials and is waiting for a response from the EPA.
Certain environmental regulations affecting CMS Energy and Consumers include, but are not limited to, the Clean Air Act Amendments of 1990 and Superfund. Superfund can require any individual or entity that may have owned or operated a disposal site, as well as transporters or generators of hazardous substances that were sent to such site, to share in remediation costs for the site.
CMS Energy's and Consumers' current insurance coverage does not extend to certain environmental clean-up costs or environmental damages, such as claims for air pollution, damage to sites owned by CMS Energy or Consumers, and for some past PCB contamination and for some long-term storage or disposal of pollutants.
For additional information concerning environmental matters, including estimated capital expenditures to reduce nitrogen oxide related emissions, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- ELECTRIC ENVIRONMENTAL ESTIMATES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- ELECTRIC ENVIRONMENTAL ESTIMATES.
CMS ENERGY AND CONSUMERS COMPETITION
ELECTRIC COMPETITION
Consumers' electric utility business experiences actual and potential competition from many sources, both in the wholesale and retail markets, as well as in electric generation, electric delivery and retail services.
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' 2004 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 2005, alternative electric suppliers are providing 900 MW of generation supply to retail open access customers. This represents approximately 12 percent of Consumers' total distribution load and an increase of approximately 23 percent in generation supply being purchased from alternative electric suppliers by retail open access customers over March 2004. In June 2004, the MPSC granted Consumers recovery of implementation costs incurred for the Electric Customer Choice program. In November 2004, the MPSC adopted a mechanism pursuant to the Customer Choice Act to provide for recovery of stranded costs that occur when customers leave Consumers' system to purchase electricity from alternative electric suppliers. Consumers cannot predict the total amount of electric supply load that may be lost to competitor suppliers.
In addition to retail electric customer choice, Consumers also has competition or potential competition from:
- customers relocating for economic reasons outside Consumers' service territory;
- municipalities owning or operating competing electric delivery systems;
- customer self-generation; and
- adjacent utilities that extend lines to customers in contiguous service territories.
Consumers addresses this competition by monitoring activity in adjacent areas and enforcing compliance with MPSC and FERC rules, providing non-energy services, and providing tariff-based incentives that support economic development.
Consumers offers non-energy revenue services to electric customers, municipalities and other utilities in an effort to offset costs. These services include engineering and consulting, construction of customer-owned distribution facilities, equipment sales (such as transformers), power quality analysis, 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, a non-utility electric subsidiary, continues to focus on optimizing 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 other utilities marketing power at lower power prices on the wholesale market.
For additional information concerning electric competition, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES.
GAS COMPETITION
Competition has existed for the past decade in various aspects of Consumers' gas utility business, and is likely to increase. Competition traditionally comes from other gas suppliers taking advantage of direct access to Consumers' customers and 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 some of the insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets.
EMPLOYEES
CMS ENERGY
As of December 31, 2004, CMS Energy and its wholly owned subsidiaries, including Consumers, had 8,660 full-time equivalent employees, of whom 8,603 are full-time employees and 57 are full-time equivalent employees associated with the part-time work force. Included in the total are 3,734 employees who are covered by union contracts.
CONSUMERS
As of December 31, 2004, Consumers and its subsidiaries had 8,050 full-time equivalent employees, of whom 7,995 are full-time employees and 55 are full-time equivalent employees associated with the part-time work force. Included in the total are 3,407 full-time operating, maintenance and construction employees and 308 full-time and part-time 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. Negotiations to reach a new contract are underway currently. 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, 2005)
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* 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 20, 2005).
CONSUMERS EXECUTIVE OFFICERS
(as of March 1, 2005)
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* 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 20, 2005).
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); and
- Board Committee Charters (including the Audit Committee and the Governance and Public Responsibility 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
SEC REQUEST
On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy voluntarily produce all documents and data relating to the SEC's inquiry into payments made to the government and officials of the government of Equatorial Guinea. On August 17, 2004, CMS Energy submitted its response, advising the SEC of the information and documentation it had available. On March 8, 2005, CMS Energy received a request from the SEC that CMS Energy voluntarily produce certain of such documents.
From 1991 through January 3, 2002, subsidiaries of CMS Energy held interest in, and beginning in 1995 operated, hydrocarbon production and processing facilities and a methanol plant in Equatorial Guinea. On January 3, 2002, CMS Energy sold all its Equatorial Guinea holdings. The SEC's inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on investigations, which reviewed the U.S. banking transactions of various foreign governments, including that of Equatorial Guinea. The investigation and hearing also reviewed the operations of certain U.S. oil companies in Equatorial Guinea. There
were no findings of violations of the U.S. Foreign Corrupt Practices Act by the U.S. oil companies in the report of the Minority Staff of the Subcommittee, the only report issued to date as a result of the hearing. The Subcommittee did find that oil companies operating in Equatorial Guinea may have contributed to corrupt practices in that country.
DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS
In May 2002, the Board of Directors of CMS Energy received a demand, on behalf of a shareholder of CMS Energy Common Stock, that it commence civil actions (i) to remedy alleged breaches of fiduciary duties by certain CMS Energy officers and directors in connection with round-trip trading by CMS MST, and (ii) to recover damages sustained by CMS Energy as a result of alleged insider trades alleged to have been made by certain current and former officers of CMS Energy and its subsidiaries. In December 2002, two new directors were appointed to the Board. The Board formed a special litigation committee in January 2003 to determine whether it is in CMS Energy's best interest to bring the action demanded by the shareholder. The disinterested members of the Board appointed the two new directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation committee, CMS Energy was served with a derivative complaint filed on behalf of the shareholder in the Circuit Court of Jackson County, Michigan in furtherance of his demands. CMS Energy cannot predict the outcome of this matter.
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. Plaintiffs are seeking to have a class certified and to have the class recover actual damages and costs, including attorneys fees. 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, LLC, which changed the name from CMS Field Services to Cantera Gas Company. CMS Energy is required to indemnify Cantera Natural Gas, LLC 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 in November 2003 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 scheme by engaging in activities to manipulate the price of natural gas in California. The complaint contains counts alleging violations of the federal Sherman Act, the California Cartwright Act, and the California Business and Professions Code relating to unlawful, unfair and deceptive business practices. The complaint seeks both actual and exemplary damages for alleged overcharges, attorneys fees and injunctive relief regulating defendants' future conduct relating to pricing and price reporting. In April 2004, a Nevada multi district court litigation (MDL) panel decided to transfer the Texas-Ohio case to a pending MDL matter in the Nevada federal district court that at the time involved seven complaints originally filed in various state courts in California. These complaints make allegations similar to those in the Texas-Ohio case regarding price reporting, although none contain a federal Sherman Act claim. In November 2004, those seven complaints, as well as a number of others that were originally filed in various state courts in California and subsequently transferred to the MDL proceeding, were remanded back to California state court. The Texas-Ohio case remains in Nevada federal district court, and defendants, with CMS Energy joining, filed a motion to dismiss, which remains pending.
Three federal putative class actions, Fairhaven Power Company v. Encana Corp. et al., Utility Savings & Refund Services LLP v. Reliant Energy Resources Inc. et al., and Abelman Art Glass v. Encana Corp. et al., all of which make allegations similar to those in the Texas-Ohio case regarding price manipulation and seek similar relief, were originally filed in the United States District Court for the Eastern District of California in September
2004, November 2004 and December 2004, respectively. The Fairhaven and Abelman Art Glass cases also include claims for unjust enrichment and a constructive trust. The three complaints were filed against CMS Energy and many of the other defendants named in the Texas-Ohio case. In addition, the Utility Savings case names CMS MST and Cantera Resources Inc. (Cantera Resources Inc. is the parent of Cantera Natural Gas, LLC. and CMS Energy is required to indemnify Cantera Natural Gas, LLC and Cantera Resources Inc. with respect to these actions.)
Both the Fairhaven and Utility Savings cases have been transferred to the MDL proceeding, where the Texas-Ohio case is pending. Pursuant to stipulation by the parties and court order, defendants are not required to respond to the Fairhaven and Utility Savings complaints until the court rules on defendants' Motion to Dismiss, which is pending in the Texas-Ohio case. Should the court grant defendants' motion without leave to amend, any remaining cases in the MDL proceeding shall be refiled as a consolidated complaint within 20 days of such ruling. If the motion is denied, or granted with leave to amend, the Texas-Ohio case and any others pending in the MDL proceeding shall be refiled as a consolidated complaint within 20 days of the court's ruling. In February 2005, the Abelman Art Glass case was conditionally transferred to the MDL proceeding. Abelman Art Glass has until March 10, 2005 to oppose the conditional transfer order.
Commencing in or about February 2004, 15 state law complaints containing allegations similar to those made in the Texas-Ohio case, but generally limited to the California Cartwright Act and unjust enrichment, were filed in various California state courts against many of the same defendants named in the federal price manipulation cases discussed above. In addition to CMS Energy, CMS MST is named in all of the 15 state law complaints. Cantera Gas Company and Cantera Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in all but the Benscheidt complaint. Two of these cases are styled as class actions, Benscheidt v. AEP Energy Services, Inc., et al. and Older v. Sempra Energy, et al., and include a claim for violation of the California Business and Professions Code relating to unlawful, unfair and deceptive business practices. Two others, City and County of San Francisco and the People of the State of California, ex rel. Dennis J. Herrera, in his official capacity as City Attorney for the City and County of San Francisco v. Sempra Energy, et al. and Owens-Brockway Glass Container Inc. v. Sempra Energy et al., also include such a claim under the California Business and Professions Code and are styled as representative actions.
In February 2005, these 15 separate actions, as well as nine other similar actions that were filed in California state court but do not name CMS Energy or any of its former or current subsidiaries, were ordered coordinated with pending coordinated proceedings in the San Diego Superior Court. The pending coordinated proceedings, Natural Gas Antitrust Cases I-IV, involve an alleged 1990's conspiracy by major gas pipeline companies not to build a new pipeline into Southern California, and a conspiracy to limit gas transmission over an existing pipeline. The 24 state court complaints involving price reporting were coordinated as Natural Gas Antitrust Cases V. Plaintiffs in Natural Gas Antitrust Cases V have been ordered to file a consolidated complaint.
Samuel D. Leggett, et al v. Duke Energy Corporation, et al, a class action complaint brought on behalf of retail and business purchasers of natural gas in Tennessee, was filed in the Chancery Court of Fayette County, Tennessee in January 2005. The complaint contains claims for violations of the Tennessee Trade Practices Act based upon allegations of false reporting of price information by defendants to publications that compile and publish indices of natural gas prices for various natural gas hubs. The complaint seeks statutory full consideration damages and attorneys fees and injunctive relief regulating defendants' future conduct. The defendants include CMS Energy, CMS MST and CMS Field Services.
CMS Energy and the other CMS defendants will defend themselves vigorously against these matters but cannot predict their outcome.
ROUND-TRIP TRADING INVESTIGATIONS
During the period of May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These so called round-trip trades had no impact on previously reported consolidated net income, earnings per share, or
cash flows, but had the effect of increasing operating revenues, operating expenses, accounts receivable, accounts payable, and reported trading volumes.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST.
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 two cases, filed in July 2002 in United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended consolidated complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge issued an opinion and order dated March 31, 2004 in connection with the motions to dismiss filed by CMS Energy, Consumers and the individuals. The judge dismissed certain of the amended counts in the plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims in the complaint. CMS Energy, Consumers and the individual defendants filed answers to the amended complaint on May 14, 2004. The judge issued an opinion and order dated December 27, 2004, conditionally granting plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than late in 2005. CMS Energy and Consumers will defend themselves vigorously but cannot predict the outcome of this litigation.
SECURITIES CLASS ACTION LAWSUITS
Beginning on May 17, 2002, a number of securities class action complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates. The complaints were filed as purported class actions in the United States District Court for the Eastern District of Michigan, by shareholders who allege that they purchased CMS Energy's securities during a purported class period. The cases were consolidated into a single lawsuit and an amended and consolidated class action complaint was filed on May 1, 2003. The consolidated complaint contains a purported class period beginning on May 1, 2000 and running through March 31, 2003. It generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. The judge issued an opinion and order dated March 31, 2004 in connection with various pending motions, including plaintiffs' motion to amend the complaint and the motions to dismiss the complaint filed by CMS Energy, Consumers and other defendants. The judge directed plaintiffs to file an amended complaint under seal and ordered an expedited hearing on the motion to amend, which was held on May 12, 2004. At the hearing, the judge ordered plaintiffs to file a Second Amended Consolidated Class Action complaint deleting Counts III and IV relating to purchasers of CMS PEPS, which the judge ordered dismissed with prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS Energy, Consumers, and the individual defendants filed new motions to dismiss on June 21, 2004. The judge issued an opinion and order dated January 7, 2005, granting the motion to dismiss for Consumers and three of the individual defendants, but denying the motions to dismiss for CMS Energy and the 13 remaining individual defendants. CMS Energy and the individual defendants will defend themselves vigorously 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 2004, CMS Energy did not submit any matters to a vote of security holders.
CONSUMERS
During the fourth quarter of 2004, 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 17 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION), which is incorporated by reference herein. At March 7, 2005, the number of registered holders of CMS Energy Common Stock totaled 57,787. In January 2003, CMS Energy suspended the payment of dividends on its common stock. Information regarding securities authorized for issuance under equity compensation plans is included in our definitive proxy statement, which is incorporated by reference herein.
CONSUMERS
Consumers' common stock is privately held by its parent, CMS Energy, and does not trade in the public market. In February, May, August, and November 2004, Consumers paid $77.5 million, $27 million, $81.9 million and $3.6 million in cash dividends, respectively, on its common stock. 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.
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)
2004 CONSOLIDATED FINANCIAL STATEMENTS
CMS-1
CMS ENERGY CORPORATION SELECTED FINANCIAL INFORMATION
- ------------------------- (a) Under revised FASB Interpretation No. 46, we are the primary beneficiary of the MCV Partnership and the FMLP. As a result, we have consolidated their assets, liabilities and activities into our financial statements as of and for the year ended December 31, 2004. These partnerships had third party obligations totaling $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $1.426 billion at December 31, 2004.
(b) Effective December 31, 2003, Trust Preferred Securities are classified on the balance sheet as long-term debt-related parties.
(c) Excludes off-system transportation customers.
CMS-2
CMS Energy Corporation Management's Discussion and Analysis
This MD&A is a consolidated report of CMS Energy and Consumers. The terms "we" and "our" as used in this report refer to CMS Energy and its subsidiaries as a consolidated entity, except where it is clear that such term means only CMS Energy.
EXECUTIVE OVERVIEW
CMS Energy is an integrated energy company with a business strategy focused primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international diversified energy businesses including independent power production and natural gas transmission, storage, and processing. We manage our businesses by the nature of services each provides. We operate principally in three business segments: electric utility, gas utility, and enterprises.
We earn our revenue and generate cash from operations by providing electric and natural gas utility services, electric power generation, gas transmission, storage, and processing. Our businesses are affected primarily by:
- weather, especially during the traditional heating and cooling seasons,
- economic conditions primarily in Michigan,
- regulation and regulatory issues that affect our gas and electric utility operations,
- interest rates,
- our debt credit rating, and
- energy commodity prices.
Our business strategy involves improving our balance sheet and maintaining focus on our core strength: superior utility operation and service. Our primary focus with respect to our non-utility businesses has been to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets, and to improve earnings and cash flow from the businesses we plan to retain. Although much of our asset sales program is complete, we still may sell certain remaining businesses that are not strategic to us. Over the next few years, we expect that this strategy will result in reduced parent company debt, improved credit ratings, earnings growth, restoration of a common stock dividend, and a company positioned to make new investments consistent with our strengths. In the near term, our new investments will focus principally on the utility.
We face important challenges in the future. We continue to lose industrial and commercial customers to alternative electric suppliers as a result of Michigan's Customer Choice Act. As of March 2005, we have lost 900 MW, or 12 percent, of our electric load to these alternative electric suppliers. Based on current trends, we predict total load loss by the end of 2005 to be in the range of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load loss will fall within that range. Existing state legislation encourages competition and provides for recovery of Stranded Costs caused by the lost sales. In fact, in November 2004, the MPSC ordered Consumers to recover 2002 and 2003 Stranded Costs in the amount of $63 million. In 2004, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act.
Another important challenge relates to the economics of the MCV Partnership. The MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. In January 2005, the MPSC issued an order approving the RCP to change the way the facility is used. The purpose of the RCP is to conserve natural gas
CMS-3
through a change in the dispatch of the MCV Facility and thereby improve the financial performance of the MCV Partnership without increased costs to customers. The approved plan will:
- allow for dispatching the MCV Facility based on natural gas market prices, which is expected to reduce gas consumption by an estimated 30 to 40 bcf per year,
- allocate 50 percent of Consumers' direct savings to customers in 2005 and 70 percent of Consumers' direct savings to customers thereafter, and
- fund $5 million annually for renewable energy sources such as wind power projects.
Our business plan is targeted at predictable earnings growth and debt reduction. Between 2001 and 2003, we reduced parent debt (ie: excluding Consumers' and other subsidiaries' debt) by 50 percent. We are now in the second year of a five-year plan to reduce further, by about half, the debt of CMS Energy. In 2004, we issued 32.8 million shares of our common stock. We also issued over $1 billion in FMBs and $288 million of convertible senior notes. Proceeds from these transactions were used to retire higher-interest rate long-term debt and to make capital infusions of $250 million into Consumers, providing additional liquidity and flexibility for our utility operations. In January 2005, we continued to retire higher-interest rate debt through the use of proceeds from the issuance of $150 million of CMS Energy senior notes and $250 million of Consumers' FMBs. We also infused an additional $200 million into Consumers in January 2005. These efforts, and others, are designed to lead us to be a strong, reliable energy company that will be poised to take advantage of opportunities for further growth.
CONSOLIDATION OF VARIABLE INTEREST ENTITIES
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of several entities, most notably the MCV Partnership and the FMLP. As a result, we have consolidated the assets, liabilities, and activities of these entities into our financial statements as of and for the year ended December 31, 2004. These entities are reported as equity method investments in our financial statements for all periods prior to January 1, 2004. For additional details, see Note 16, Implementation of New Accounting Standards.
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 Exchange 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:
- capital and financial market conditions, including the price of CMS Energy Common Stock and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets as well as availability of financing to CMS Energy, Consumers, or any of their affiliates, and the energy industry,
- market perception of the energy industry, CMS Energy, Consumers, or any of their affiliates,
- credit ratings of CMS Energy, Consumers, or any of their affiliates,
- currency fluctuations, transfer restrictions, and exchange controls,
- factors affecting utility and diversified energy operations such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints,
- international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments, CMS-4
- adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions,
- potentially adverse regulatory treatment and/or regulatory lag concerning a number of significant questions presently before the MPSC relating to the Customer Choice Act including:
- recovery of future Stranded Costs incurred due to customers choosing alternative energy suppliers,
- recovery of Clean Air Act costs and other environmental and safety-related expenditures,
- power supply and natural gas supply costs when oil prices and other fuel prices are rapidly increasing,
- timely recognition in rates of additional equity investments in Consumers, and
- adequate and timely recovery of additional electric and gas rate-based expenditures,
- the impact of adverse natural gas prices on the MCV Partnership investment, and regulatory decisions that limit our recovery of capacity and fixed energy payments,
- federal regulation of electric sales and transmission of electricity including periodic re-examination by federal regulators of the market-based sales authorizations under which our subsidiaries participate in wholesale power markets without price restrictions,
- energy markets, including the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity, and certain related products due to lower or higher demand, shortages, transportation problems, or other developments,
- potential for the Midwest Energy Market to develop into an active energy market in the state of Michigan, which may lead us to account for electric capacity and energy contracts with the MCV Partnership and other independent power producers as derivatives,
- the GAAP requirement that we utilize mark-to-market accounting on certain of our energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods and could add to earnings volatility,
- potential disruption, expropriation or interruption of facilities or operations due to accidents, war, terrorism, or changing political conditions and the ability to obtain or maintain insurance coverage for such events,
- nuclear power plant performance, decommissioning, policies, procedures, incidents, and regulation, including the availability of spent nuclear fuel storage,
- technological developments in energy production, delivery, and usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or policies,
- outcome, cost, and other effects of legal and administrative proceedings, settlements, investigations and claims, including particularly claims, damages, and fines resulting from round-trip trading and inaccurate commodity price reporting, including investigations by the DOJ regarding round-trip trading and price reporting,
- 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,
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- the efficient sale of non-strategic or under-performing domestic or international assets and discontinuation of certain operations,
- other business or investment considerations that may be disclosed from time to time in CMS Energy's or Consumers' SEC filings or in other publicly issued written documents, and
- other uncertainties that are difficult to predict, and many of which are beyond our control.
RESULTS OF OPERATIONS
Our business strategy involves improving our balance sheet and maintaining focus on our core strength: superior utility operation and service. Our primary focus with respect to our non-utility businesses has been to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets, and to improve earnings and cash flow from the businesses we plan to retain. The level of inflation in the U.S. and in other countries in which we have businesses or investments has not had a significant effect on our consolidated results of operations.
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
2004 COMPARED TO 2003: For the year ended December 31, 2004, our net income available to common stockholders was $110 million, compared to a net loss available to common stockholders of $44 million for the year ended December 31, 2003. The improvement reflects the increased earnings from our utility due in large part to rulings from the MPSC. The increase also reflects our continued commitment to cost management, the continued reduction of debt at our parent company, lower interest expense from refinanced debt, and benefits from recent tax legislation. This improvement was offset partially by increased impairment charges as we continued to dispose of certain businesses that are not strategic to us. Net income was also reduced by an environmental remediation charge related to our involvement in Bay Harbor.
Specific increases to net income available to common stockholders are:
- a $56 million increase in net income at our electric utility as favorable treatment of depreciation and interest under the Customer Choice Act and reduced pension and benefit costs more than offset the effects of milder weather, reduced tariff revenues equivalent to the Big Rock nuclear decommissioning surcharge, and customers choosing alternative electric suppliers,
- a $56 million net reduction in corporate interest expense,
- a $35 million net gain from the 2004 sales of our Parmelia business and our interest in Goldfields;
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- a $33 million increase in net income at our gas utility resulting from favorable impacts of MPSC rate orders, reduced pension and benefit costs outpacing increased interest costs, and the effects of milder weather,
- a $21 million income tax benefit recorded at Enterprises resulting from the American Jobs Creation Act of 2004,
- a $20 million net reduction in operating and maintenance expenses at Enterprises resulting from a reduction in expenses at CMS ERM, which sold its non-essential business segments and moved its headquarters from Houston, Texas to Jackson, Michigan in 2003,
- a $5 million net reduction in debt retirement charges,
- a $22 million reduction in charges related to changes in accounting, and
- the absence in 2004 of a $34 million deferred tax asset valuation reserve established in 2003.
These increases were offset partially by:
- a $36 million increase in net asset impairment charges,
- a $29 million net environmental remediation charge associated with our involvement in Bay Harbor,
- a $10 million increase in the declaration and payment of CMS Energy preferred dividends;
- the absence in 2004 of $30 million of MSBT refunds received in 2003, and
- the absence in 2004 of $23 million in gains in Discontinued Operations recorded in 2003.
2003 COMPARED TO 2002: For the year ended December 31, 2003, our net loss available to common stockholders was $44 million, compared to a net loss available to common stockholders of $650 million for the year ended December 31, 2002. The improvement reflects the absence of impairment charges from businesses that were not strategic to us, reduced corporate debt, and increased earnings from equity method investments. These improvements were offset partially by lower earnings at our electric utility, a net settlement and curtailment loss related to our employee benefit plans, and changes in accounting.
Specific increases to net income available to common stockholders are:
- the absence in 2003 of $379 million of net goodwill impairments associated with discontinued operations recorded in 2002,
- a $427 million increase in net income at Enterprises, primarily due to a significant reduction in asset impairment charges and increased earnings from equity investments,
- $30 million of MSBT refunds, and
- a $25 million net reduction in corporate interest.
These increases were offset partially by:
- a $97 million reduction in net income from our electric utility due to the impact of milder weather on electric deliveries, higher pension expense, greater depreciation and amortization expense, and customers choosing alternative electric suppliers,
- a $48 million net settlement and curtailment charge related to a large number of employees retiring and exiting our employee benefit plans,
- a $44 million net loss on the sale of Panhandle,
- a $34 million deferred tax asset valuation reserve established in 2003,
- a $24 million charge related to changes in accounting primarily due to energy trading contracts that did not meet the definition of a derivative, and
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- an $8 million decrease in net income at our gas utility primarily due to increased pension and benefit expense, greater depreciation expense and higher average debt levels, offset partially by the favorable impact of a MPSC rate order.
ELECTRIC UTILITY RESULTS OF OPERATIONS
ELECTRIC DELIVERIES: For the year 2004, electric deliveries including transactions with other wholesale marketers, other electric utilities, and customers choosing alternative electric suppliers increased 1.3 billion kWh or 3.3 percent versus 2003. Despite the increase in electric deliveries, electric delivery revenue decreased due to the milder summer temperatures' negative impact on higher margin residential customer air conditioning usage, customers choosing alternative electric suppliers, and tariff revenue reductions. The tariff revenue reductions began on January 1, 2004, and were equivalent to the Big Rock nuclear decommissioning surcharge in effect when our electric retail rates were frozen from June 2000 through December 31, 2003. The tariff revenue reductions decreased electric delivery revenue by $35 million.
Surcharges related to the recovery of costs incurred in the transition to customer choice offset partially the reductions to electric delivery revenue. Recovery of these costs began on July 1, 2004 and increased electric delivery revenue by $10 million.
For the year 2003, electric delivery revenue decreased, reflecting lower deliveries versus 2002. Most significantly, sales volumes to commercial and industrial customers were lower than in 2002, a result of these sectors' continued migration to alternative electric suppliers as allowed by the Customer Choice Act. Milder summer temperatures reduced air conditioning usage by the higher-margin residential customers, further decreasing electric delivery revenue. Overall, electric deliveries, including transactions with other wholesale marketers and other electric utilities, decreased 0.4 billion kWh or 1.1 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: For the year 2004, our recovery of power supply costs was capped for the residential and small commercial customer classes. Operating income decreased $31 million in 2004 versus 2003 primarily due to power supply-related costs exceeding power supply-related revenue charged to capped customers. Power supply-related costs increased in 2004 primarily due to higher priced purchased power necessary to replace the generation loss from an extended refueling outage at our Palisades nuclear generating plant and higher coal prices.
For the year 2003, our recovery of power supply costs was fixed for all customers, as required under the Customer Choice Act. Therefore, power supply-related revenue in excess of actual power supply costs increased operating income. By contrast, if power supply-related revenue had been less than actual power supply costs, the impact would have decreased operating income. For the year 2003, power supply-related revenue in excess of actual power supply costs benefited operating income by $26 million versus 2002. This increase was primarily the
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result of increased intersystem revenue, efficient operation of our generating plants, and lower priced purchased power.
OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: For the year 2004, other income increased $7 million, other operating expenses decreased $82 million, and non-commodity revenue decreased $3 million versus 2003. Other income increased primarily due to $7 million of interest income related to our 2002 and 2003 Stranded Cost recovery as authorized by the MPSC. Our recognition of this recovery decreased operating expense $57 million in 2004, and along with decreased depreciation, pension, and benefit costs contributed to the reduction in other operating expenses. The decrease in depreciation expense reflects our ability to defer depreciation expense on the excess of capital expenditures over our depreciation base as authorized by the Customer Choice Act. The decrease in pension expense reflects fewer current year retirees choosing to receive a single lump sum distribution and increased plan earnings from higher average plan assets. The reduction in benefit expense is due to the subsidy provided under Part D of the Medicare Prescription Drug, Improvement and Modernization Act.
For the year 2003, net other operating expenses, other income and non-commodity revenue decreased operating income versus 2002. The decrease related to increased pension and other benefit costs, a scheduled refueling outage at Palisades, and higher transmission costs. In addition, depreciation and amortization expense increased, reflecting higher levels of plant in service, and higher amortization of securitized assets. Higher non-commodity revenue associated with other income offset slightly the increased operating expenses.
REGULATORY RETURN ON CAPITAL EXPENDITURES: As allowed by Section 10d(4) of the Customer Choice Act, on January 1, 2004, we began recording the 2004 portion of the return on certain capital expenditures incurred during the rate freeze period of June 2000 through December 2003. This increased income by $41 million in 2004. Based on an interpretation of the Customer Choice Act by the MPSC in a rate order involving Detroit Edison, in November 2004 we recorded an additional $72 million return on Clean Air Act costs incurred during the period of June 2000 through December 2003.
GAIN ON ASSET SALES: The reduction in operating income from asset sales for 2003 versus 2002 reflected 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: For the year 2004, general taxes increased primarily due to increases in property tax expense and the absence of a MSBT credit received in 2003. The 2003 MSBT credit was associated with the construction of our corporate headquarters on a qualifying Brownfield site. For the year 2003, this MSBT credit decreased general taxes versus 2002.
FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest. Additionally, to recognize a recently issued interpretation of the Customer Choice Act by the MPSC, we expensed $31 million of capitalized interest in November related to Clean Air Act costs incurred during the period of June 2000 through December 2003.
For the year 2003, fixed charges increased versus 2002 due to higher average debt levels and higher average interest rates.
INCOME TAXES: For the year 2004, income taxes increased due to increased earnings from the electric utility versus 2003. The increase in income taxes from the tax treatment of items related to plant, property and equipment as required by past MPSC orders was offset by Part D of the Medicare Prescription Drug, Improvement and Modernization Act which provides a subsidy that is exempt from federal taxation. For the year 2003, income tax expense decreased versus 2002 primarily due to lower earnings by the electric utility.
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GAS UTILITY RESULTS OF OPERATIONS
GAS DELIVERIES: For the year 2004, gas deliveries, including transportation to end-use customers, decreased 15.5 bcf or 4.6 percent due to milder weather versus 2003. Most significantly, temperatures in the first quarter of the year were 12.1 percent warmer than in the same period in 2003.
For the year 2003, gas deliveries, including miscellaneous transportation, increased due to colder weather during the first quarter of 2003 versus 2002. Increased deliveries to the residential and commercial sectors resulted in a $6 million increase in gas revenue. This revenue increase was offset by a $7 million reduction to gas revenue associated with our analysis of gas losses related to the gas transmission and distribution system.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order authorizing a $19 million annual increase to gas tariff rates. In October 2004, the MPSC issued a final order authorizing an increase of $58 million in each of the next two years. As a result of these orders, gas revenues increased $28 million for the year 2004 versus 2003.
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, gas revenue increased $39 million for the year 2003 versus 2002.
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUE AND OTHER INCOME: In 2004, gas wholesale and retail services and other gas revenue increased primarily due to the absence of certain 2003 reductions to revenue. In 2003, gas revenue was reduced primarily due to an $11 million 2002-2003 GCR disallowance.
For the year 2003, gas wholesale and retail services and other gas revenue increased versus 2002. This increase was primarily due to increased gas title tracking services and miscellaneous revenue in 2003. The increased revenue was offset partially by a disallowance for the 2002-2003 GCR year.
OPERATION AND MAINTENANCE: For the year 2004 versus 2003, operation and maintenance expenses decreased versus 2003 primarily due to reduced pension and benefit expense of $23 million. The decrease in pension expense reflects fewer current year retirees choosing to receive a single lump sum distribution and increased plan earnings from higher average plan assets. The reduction in benefit expense is due to the subsidy provided under Part D of the Medicare Prescription Drug, Improvement and Modernization Act. These reductions were offset partially by additional expenditures on safety, reliability, and customer service.
For the year 2003, operation and maintenance expenses increased versus 2002 due to increases in pension and other benefit costs of $27 million and additional expenditures on safety, reliability, and customer service.
GENERAL TAXES: For the year 2004, general taxes increased due to the absence of a MSBT credit received in 2003. The 2003 MSBT credit received from the State of Michigan was associated with the construction of our corporate headquarters on a qualifying Brownfield site. For the year 2003, this MSBT credit decreased general taxes versus 2002.
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DEPRECIATION: For the year 2004 versus 2003, depreciation expense decreased primarily due to reduced rates authorized by the MPSC's December 2003 interim rate order and the MPSC's October 2004 order, as modified by its December 2004 order granting rehearing. For the year 2003, depreciation expense increased because of increased plant in service versus 2002.
FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest. For the year 2003, fixed charges increased versus 2002 due to higher average debt levels and higher average interest rates.
INCOME TAXES: For the year 2004, income taxes increased due to increased earnings from the gas utility versus 2003. The increase in income taxes was offset partially by reductions from the tax treatment of items related to plant, property and equipment as required by past MPSC orders, and by Part D of the Medicare Prescription Drug, Improvement and Modernization Act which provides a subsidy that is exempt from federal taxation.
For the year 2003 versus 2002, income tax expense increased primarily due to the tax treatment of items related to plant, property and equipment as required by past MPSC orders.
ENTERPRISES RESULTS OF OPERATIONS
RESULTS OF FASB INTERPRETATION NO. 46: Due to the implementation of FASB Interpretation No. 46, certain equity investments, determined to be variable interest entities under this interpretation, which were previously included in equity earnings are now included as fully consolidated subsidiaries in the results of operations. The MCV Partnership and the FMLP were determined to be variable interest entities under this interpretation, and are included as fully consolidated subsidiaries in the results of operations in 2004. Three electric generating plants in Michigan, T.E.S. Filer City Station Limited Partnership, Grayling Generating Station Limited Partnership, and Genesee Power Station Limited Partnership, were determined to be variable interest entities under this interpretation and were included in the results of operations beginning in 2003. For comparability purposes, the change in net earnings of these entities is presented separately.
For 2004, earnings decreased versus 2003 primarily due to mark-to-market losses related to gas contracts and increased fuel and dispatch costs at the MCV Partnership. These decreases were offset partially by dispatch and variable energy rate variance revenue.
For 2003 versus 2002, consolidation of the three electric generating plants in Michigan had no impact on earnings.
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OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For 2004, operating revenues, net of the related cost of gas and purchased power, increased versus 2003. This increase was primarily due to higher margins from South American subsidiaries, offset partially by the sale of wholesale gas and power contracts at CMS ERM.
For 2003, operating revenues, net of the related cost of gas and purchased power, decreased versus 2002 primarily due to the sale of wholesale gas and power contracts at CMS ERM.
EARNINGS FROM EQUITY METHOD INVESTEES: Earnings from equity method investees decreased for 2004 versus 2003 due to a reduction in earnings from Goldfields, which was sold in August 2004, and losses on the settlement of derivative contracts. These decreases were offset partially by earnings from Shuweihat, which became partially operational during the fourth quarter of 2004.
Equity earnings increased for 2003 versus 2002 due to impairment losses in 2002 and an increase in mark-to-market valuation adjustments on interest rate swaps and power contracts in 2003. Lower earnings offset these increases partially in 2003 due to sales of equity investments in 2002.
OPERATION AND MAINTENANCE: Operating and maintenance decreased for 2004 versus 2003 and for 2003 versus 2002. These decreases were the result of a reduction in expenses at CMS ERM, which sold its non-essential business segments and moved its headquarters from Houston, Texas to Jackson, Michigan in 2003.
GENERAL TAXES, DEPRECIATION AND OTHER INCOME: For 2004, the net of general tax expense, depreciation and other income decreased income versus 2003. The change was due to foreign exchange losses offset partially by lower depreciation due to the sale of non-essential assets at ERM in 2003.
For 2003, the net of general tax expense, depreciation and other income increased income versus 2002. The change was due to lower depreciation from assets impaired in 2002, higher interest income, and foreign exchange gains offset partially by higher general taxes.
GAIN (LOSS) ON SALE OF ASSETS: Gains on asset sales increased in 2004 versus 2003. This is primarily due to the gains on the sales of Goldfields and land in Moapa, Nevada in 2004.
For 2003, loss on asset sales increased versus 2002. This is primarily due to the losses on the sales of CMS ERM Wholesale Gas contracts and Guardian Pipeline in 2003.
For additional details, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring.
ASSET IMPAIRMENT CHARGES: Asset impairment charges increased in 2004 versus 2003. Impairments recorded in 2004 included a reduction in the fair value of Loy Yang and impairments related to the sales of our interests in SLAP and GVK. In February 2005, we completed the sale of our interest in GVK. We expect to complete the sale of SLAP in 2005.
Asset impairment charges decreased in 2003 versus 2002. In 2003, the impairments of our equity investments at CMS Generation and our investment in CMS Electric and Gas' Venezuelan distribution utility were significantly lower than our 2002 asset impairments that were related primarily to DIG and Michigan Power.
For additional details, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring.
ENVIRONMENTAL REMEDIATION: For 2004, we recorded estimated environmental remediation costs for indemnification claims related to our involvement in Bay Harbor.
For additional details, see Note 3, Contingencies.
FIXED CHARGES: For 2004, fixed charges decreased versus 2003 due to lower average debt levels and lower average interest rates primarily resulting from the payoff of a short-term revolving credit line held by Enterprises during 2003, offset partially by the payment of preferred dividends to the investor in our Michigan gas assets in 2004 and higher letter of credit fees.
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For 2003, fixed charges increased versus 2002 due to higher average debt levels and higher average interest rates primarily due to a short-term revolving credit line held by Enterprises during part of 2003.
INCOME TAXES: For 2004, income taxes decreased as compared to 2003 primarily due to the foreign earnings repatriation tax benefit arising from the American Jobs Creation Act of 2004, and a decrease in tax reserves.
For 2003, income taxes increased as compared to 2002 due to the absence in 2003, of the tax benefit related to the 2002 impairment charges.
CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS
For the year ended December 31, 2004, corporate interest and other net expenses were $197 million, a decrease of $59 million versus the same period in 2003. The decrease reflects $56 million of lower interest due to lower average debt levels and a 58 basis point reduction in the average rate of interest, a $5 million reduction in debt retirement charges, and the absence in 2004 of a $34 million deferred tax asset valuation reserve established in 2003. These decreases were offset partially by a $24 million increase in general taxes primarily due to the absence of MSBT refunds received in 2003, a $10 million increase in the declaration and payment of CMS Energy preferred dividends and a $2 million increase in other various expenses.
Our 2003 corporate interest and other net expenses decreased $29 million from 2002 primarily due to reduced restructuring costs and reduced taxes, offset partially by an increase in interest allocated to continuing operations.
DISCONTINUED OPERATIONS: For the year ended December 31, 2004, our net loss from Discontinued Operations was $4 million, a decrease of $27 million versus the same period in 2003. The net loss for 2004 was related primarily to income tax adjustments offset partially by gains on asset sales. Income from 2003 primarily reflects an increase to net income due to the reclassification of our international energy distribution business from discontinued operations to continuing operations. The reclassification resulted in a reversal of a previously recognized impairment loss. This increase was offset partially by an impairment of Parmelia, interest allocated to discontinued operations, and a loss on the disposal of CMS Viron.
For additional details, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring.
ACCOUNTING CHANGES: In 2004, we recorded a $2 million loss for the cumulative effect of a change in accounting principle. The loss was the result of a change in the measurement date on our benefit plans. For additional details, see Note 7, Retirement Benefits.
A $24 million loss for the cumulative effect of changes in accounting principle was recognized in the first quarter of 2003, of which $23 million was related to energy trading contracts and $1 million was related to asset retirement obligations.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A:
- use of estimates and assumptions in accounting for long-lived assets, contingencies, and equity method investments,
- accounting for the effects of industry regulation
- accounting for financial and derivative instruments, trading activities, and market risk information,
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- accounting for international operations and foreign currency,
- accounting for pension and OPEB,
- accounting for asset retirement obligations, and
- accounting for nuclear decommissioning costs.
For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, we use estimates and assumptions that may affect reported amounts and disclosures. Accounting estimates are used for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, and contingencies. For example, we estimate the rate of return on plan assets and the cost of future health-care benefits to determine our annual pension and other postretirement benefit costs. There are risks and uncertainties that may cause actual results to differ from estimated results, such as changes in the regulatory environment, competition, foreign exchange, regulatory decisions, and lawsuits.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. Tests of impairment are performed periodically if certain conditions that are other than temporary exist that may indicate the carrying value may not be recoverable. Of our total assets, recorded at $15.872 billion at December 31, 2004, 59 percent represent long-lived assets and equity method investments that are subject to this type of analysis. We base our evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- domestic and foreign regulatory and political environments,
- state and federal regulatory and political environments,
- historical and future cash flow and profitability measurements, and
- other external market conditions or factors.
If an event occurs or circumstances change in a manner that indicates the recoverability of a long-lived asset should be assessed, we evaluate the asset for impairment. An asset held-in-use is evaluated for impairment by calculating the undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. If the undiscounted future cash flows are less than the carrying amount, we recognize an impairment loss. The impairment loss recognized is the amount by which the carrying amount exceeds the fair value. We estimate the fair market value of the asset utilizing the best information available. This information includes quoted market prices, market prices of similar assets, and discounted future cash flow analyses. An asset considered held-for-sale is recorded at the lower of its carrying amount or fair value, less cost to sell.
We also assess our ability to recover the carrying amounts of our equity method investments. This assessment requires us to determine the fair values of our equity method investments. The determination of fair value is based on valuation methodologies including discounted cash flows and the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. We also consider the existence of CMS Energy guarantees on obligations of the investee or other commitments to provide further financial support. If the fair value is less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded.
Our assessments of fair value using these valuation methodologies represent our best estimates at the time of the reviews and are consistent with our internal planning. The estimates we use can change over time. If fair values were estimated differently, they could have a material impact on our financial statements.
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 of
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loss is probable and the amount of loss can be reasonably estimated. 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 pending class actions arising out of round-trip trading and gas price reporting, our electric and gas environmental estimates, our indemnity and environmental remediation obligations at Bay Harbor, and the potential underrecoveries from our power purchase contract with the MCV Partnership.
The amount of income taxes we pay is subject to ongoing audits by federal, state, foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have adequately provided for any likely outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments expire. As a result, our effective tax rate may fluctuate significantly on a quarterly basis.
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.
The cost that we incur under the MCV Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate that cash underrecoveries of capacity and fixed energy payments will aggregate $150 million from 2005 through 2007. After September 15, 2007, we expect to claim relief under the regulatory out provision in the PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts collected from our customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse effect on our investment, and
- eliminate our underrecoveries of capacity and fixed energy payments.
The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 2007 may affect negatively the earnings of the MCV Partnership and the value of our investment in the MCV Partnership.
Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. Even with the approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment.
In January 2005, the MPSC issued an order approving the RCP, with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility on the basis of natural gas market prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit our ownership interest in the MCV Partnership.
The substantial MCV Facility fuel cost savings will be used first to offset fully the cost of replacement power. Second, $5 million annually will be used to fund a renewable energy program. Remaining savings will be split between the MCV Partnership and Consumers. Consumers' direct savings will be shared 50 percent with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct savings from the RCP, after a portion is allocated to customers, will be used to offset our capacity and fixed energy underrecoveries expense. Since the MPSC has excluded these underrecoveries from the rate making process, we anticipate that our savings from the RCP will not affect our return on equity used in our base rate filings.
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In January 2005, Consumers and the MCV Partnership's general partners accepted the terms of the order and implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed an application for rehearing of the MPSC order. The Attorney General also filed a claim of appeal with the Michigan Court of Appeals. We cannot predict the outcome of these appeals.
For additional details on the MCV Partnership, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration Venture."
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity.
For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate they will require 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, 2004, we had $1.696 billion recorded as regulatory assets and $1.574 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, 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 classified as available-for-sale are reported at fair value determined from quoted market prices. Debt and equity securities classified as held-to-maturity are reported at cost. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary.
Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our earnings or cash flows.
DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if certain contracts must be accounted for as derivative instruments. This criteria is complex and significant judgment is often required in applying the criteria to specific contracts. 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 is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in fair value (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income, depending on whether the derivative qualifies for cash flow hedge accounting treatment.
The types of contracts we typically classify as derivative instruments are interest rate swaps, foreign currency exchange contracts, electric call options, gas supply call and put options, gas fuel futures and swaps, gas fuel options, certain gas fuel contracts, and certain gas and electric forward contracts. The majority of our contracts are not subject to derivative accounting under SFAS No. 133 because they qualify for the normal purchases and sales exception, or because there is not an active market for the commodity. Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market for the coal that we purchase. If active
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markets for these commodities develop in the future, we may be required to account for these contracts as derivatives, and the resulting mark-to-market impact on earnings could be material to our financial statements.
The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005, which will include day-ahead and real-time energy market information and centralized dispatch for market participants. At this time, we believe that the commencement of this market will not constitute the development of an active energy market in the state of Michigan. However, after having adequate experience with the Midwest Energy Market, we will reevaluate whether or not the activity level within this market leads to the conclusion that an active energy market exists. For additional information, see "Electric Utility Business Uncertainties -- Competition and Regulatory Restructuring -- Transmission Market Developments" within this MD&A.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that certain of its long-term gas contracts qualify as normal purchases under SFAS No. 133 and therefore, these contracts are not recognized at fair value on the balance sheet. Due to the implementation of the RCP in January 2005, the MCV Partnership has determined that a significant portion of its gas fuel contracts no longer qualify as normal purchases because the contracted gas will not be consumed as fuel for electric production. Accordingly, these contracts will be treated as derivatives and will be marked-to-market through earnings each quarter, which could increase earnings volatility. Based on market prices for natural gas as of January 31, 2005, the accounting for the MCV Partnership's long-term gas contracts, including those affected by the implementation of the RCP, could result in an estimated $100 million (pretax before minority interest) gain recorded to earnings in the first quarter of 2005. This estimated gain will reverse in subsequent quarters as the contracts settle. For further details on the RCP, see "Critical Accounting Policies -- Use of Estimates and Assumptions -- MCV Underrecoveries" within this MD&A. If there are further changes in the level of planned electric production or gas consumption, the MCV Partnership may be required to account for additional long-term gas contracts as derivatives, which could add to earnings volatility.
To determine the fair value of our derivative contracts, we use a combination of quoted market prices, prices obtained from external sources, such as brokers, and mathematical valuation models. Valuation models require various inputs, including forward prices, strike prices, volatilities, interest rates, and maturity dates. Changes in forward prices or volatilities could change significantly the calculated fair value of certain contracts. At December 31, 2004, we assumed a market-based interest rate of 2.75 percent and monthly volatility rates ranging between 38 percent and 73 percent to calculate the fair value of our gas options. Also, at December 31, 2004, we assumed a market-based interest rate of 2.75 percent and daily volatility rates ranging between 80 percent and 157 percent to calculate the fair value of our electric options. At December 31, 2004, we assumed market-based interest rates ranging between 2.40 percent and 4.48 percent (depending on the term of the contract) and monthly volatility rates ranging between 25 percent and 68 percent to calculate the fair value of the gas fuel derivative contracts held by the MCV Partnership.
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. In connection with the market valuation of our derivative contracts, we maintain reserves, if necessary, for credit risks based on the financial condition of counterparties.
CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts that are related to activities considered to be an integral part of CMS Energy's ongoing operations. CMS ERM holds certain forward contracts for the purchase and sale of electricity and natural gas that result in physical delivery of the underlying commodity at contractual prices. These contracts are generally long-term in nature and are classified as non-trading. CMS ERM also uses various financial instruments, including swaps, options, and futures, to manage the commodity price risks associated with its forward purchase and sales contracts as well as generation assets owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading activities. Non-trading and trading contracts that meet the definition of a derivative under SFAS No. 133 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. Gains and losses on trading
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contracts are recorded net in accordance with EITF Issue No. 02-03. Contracts that do not meet the definition of a derivative are accounted for as executory contracts (i.e., on an accrual basis).
The fair value of the derivative contracts held by CMS ERM is included in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The following tables provide a summary of these contracts as of December 31, 2004:
- ------------------------- (a) Reflects only the initial premium payments/(receipts) for new contracts. No unrealized gains or losses were recognized at the inception of any new contracts.
(b) Reflects changes in price and net increase/(decrease) of forward positions as well as changes to mark-to-market and credit reserves.
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 derivative contracts to manage these risks, including swaps, options, futures, and forward contracts. We intend that gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. Risk management contracts are classified as either non-trading or 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 through established credit policies that include performing financial credit reviews of our counterparties. Determination of our counterparties' credit
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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 earnings as a result of counterparty nonperformance.
The following risk sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our derivative contracts and other financial instruments based upon a hypothetical 10 percent adverse change in market rates or prices. Changes in excess of the amounts shown in the sensitivity analyses could occur if market rates or prices exceed the 10 percent shift used for the analyses.
Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital.
Interest Rate Risk Sensitivity Analysis (assuming 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.
Certain equity method investees have entered into interest rate swaps. These instruments are not required to be included in the sensitivity analysis, but can have an impact on financial results.
Commodity Price Risk: For purposes other than trading, we enter into electric call options and gas supply call and put options. Electric call options are purchased to protect against the risk of fluctuations in the market price of electricity, and to ensure a reliable source of capacity to meet our customers' electric needs. Purchased electric call options give us the right, but not the obligation, to purchase electricity at predetermined fixed prices. Our gas supply call and put options are used to purchase reasonably priced gas supply. Purchases of gas supply call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Gas supply put options sold give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices. At December 31, 2004, we held gas supply call options and had sold gas supply put options. Also, at December 31, 2004, CMS ERM held certain non-trading derivative contracts for the purchase and sale of electricity and natural gas as further explained under "CMS ERM Contracts" within this section.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. Some of these contracts are treated as derivative instruments. The MCV Partnership also enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements.
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
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We did not perform a sensitivity analysis for the derivative contracts held by the MCV Partnership as of December 31, 2003, because the MCV Partnership was not consolidated into our financial statements until 2004, as discussed in Note 16, Implementation of New Accounting Standards.
Trading Activity Commodity Price Risk: CMS ERM uses various financial instruments, including swaps, options, and futures, to manage the commodity price risks associated with its forward purchase and sales contracts as well as generation assets owned by CMS Energy or its subsidiaries.
Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
Currency Exchange Risk: We are exposed to currency exchange risk arising from investments in foreign operations as well as various international projects in which we have an equity interest and which have debt denominated in U.S. dollars. We may use forward exchange contracts and other risk mitigating instruments to hedge currency exchange rates. The 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. As of December 31, 2004, we had no outstanding foreign exchange contracts.
Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available-for-sale investments.
Investment Securities Price Risk Sensitivity Analysis:
- ------------------------- (a) Primarily SERP Investments.
(b) Assumes a 10 percent adverse change in market prices.
(c) Assumes a 50 basis point increase in the yield to maturity of the 10-year Treasury Note, which approximates a 10 percent change in market yields.
Consumers maintains trust funds, as required by the NRC, which may only be used to fund certain costs of nuclear plant decommissioning. As of December 31, 2004 and 2003, these funds were invested primarily in equity securities, fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are recorded at fair value on our Consolidated Balance Sheets. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear plant decommissioning recognizes that costs are recovered through Consumers' electric rates, fluctuations in equity prices or interest rates do not affect earnings or cash flows.
For additional details on market risk and derivative activities, see Note 6, Financial and Derivative Instruments.
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INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects in selected markets around the world. As a result of a change in business strategy, we have been selling certain foreign investments. For additional details on the divestiture of foreign investments, see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and Restructuring.
BALANCE SHEET: Our subsidiaries and affiliates whose functional currency is other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect at the end of the fiscal period. Gains or losses that result from this translation and gains or losses on long-term intercompany foreign currency transactions are reflected as a component of stockholders' equity on our Consolidated Balance Sheets as "Accumulated Other Comprehensive Loss." As of December 31, 2004, cumulative foreign currency translation decreased stockholders' equity by $319 million. We translate the revenue and expense accounts of these subsidiaries and affiliates into U.S. dollars at the average exchange rate during the period.
Australia: The Foreign Currency Translation component of stockholders' equity at December 31, 2003 included an approximate $110 million unrealized net foreign currency translation loss related to our investment in Loy Yang and an approximate $6 million unrealized net foreign currency translation gain related to our investments in SCP and Parmelia. In March 2004, we recognized the Loy Yang foreign currency translation loss in earnings as a component of the Loy Yang impairment of approximately $81 million, net of tax, recorded as a result of the sale of Loy Yang that was completed in April 2004. In August 2004, we sold our investments in SCP and Parmelia and recognized the $6 million foreign currency translation gain. As of December 31, 2004, we no longer have any investments in Australia.
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 Argentine peso, converted all dollar-denominated utility tariffs and energy contract obligations into pesos at the same one-to-one exchange rate, and directed the President of Argentina to renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional currency for our Argentine investments. We had used previously the U.S. dollar as the functional currency. As a result, we translated the assets and liabilities of our Argentine entities into U.S. dollars using an exchange rate of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign Currency Translation component of stockholders' equity of $400 million.
As of December 31, 2004, the net foreign currency loss due to the unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency Translation component of stockholders' equity using an exchange rate of 2.976 pesos per U.S. dollar was $264 million. This amount also reflects the effect of recording, at December 31, 2002, U.S. income taxes on temporary differences between the book and tax bases of foreign investments, including the foreign currency translation associated with our Argentine investments.
INCOME STATEMENT: We use the U.S. dollar as the functional currency of subsidiaries operating in highly inflationary economies and of subsidiaries that meet the U.S. dollar functional currency criteria in SFAS No. 52. Gains and losses that arise from transactions denominated in a currency other than the U.S. dollar, except those that are hedged, are included in determining net income.
HEDGING STRATEGY: We may use forward exchange and option contracts to hedge certain receivables, payables, long-term debt, and equity value relating to foreign investments. The purpose of our foreign currency hedging activities is to protect the company from the risk associated with adverse changes in currency exchange rates that could affect cash flow materially. These contracts would limit the risk from exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on assets and liabilities being hedged.
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. We have implemented a cash balance plan for certain employees hired after June 30, 2003. We use SFAS No. 87 to account for pension costs.
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401(k): In our efforts to reduce costs, the employer's match for the 401(k) plan was suspended effective September 1, 2002. The employer's match for the 401(k) plan resumed on January 1, 2005.
OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. We use SFAS No. 106 to account for other postretirement benefit costs.
Liabilities for both pension and OPEB are recorded on the balance sheet at the present value of their future obligations, net of any plan assets. The calculation of the liabilities and associated expenses requires the expertise of actuaries. Many assumptions are made including:
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
Any change in these assumptions can significantly change the liability and associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
Actual future pension cost and contributions will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the Pension Plan.
Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated pension cost for 2005 by $3 million. Lowering the discount rate by 0.25 percent (from 6.00 percent to 5.75 percent) would increase estimated pension cost for 2005 by $4 million.
For additional details on postretirement benefits, see Note 7, Retirement Benefits.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143 became effective January 2003. It requires companies to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. For our regulated utility, as required by SFAS No. 71, we account for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions, such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded
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for these assets. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock are based on decommissioning studies that largely utilize third-party cost estimates. For additional details on ARO, see Note 8, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our Big Rock and Palisades nuclear plants. We have established external trust funds to finance the decommissioning of both plants. We record the trust fund balances as a non-current asset on our Consolidated Balance Sheets.
Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent landscape,
- all contaminated equipment and material will be removed and disposed of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us develop decommissioning cost estimates. Various inflation rates for labor, non-labor, and contaminated equipment disposal costs are used to escalate these cost estimates to the future decommissioning cost. A portion of future decommissioning cost will result from the failure of the DOE to remove fuel from the sites, as required by the Nuclear Waste Policy Act of 1982.
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. The funds provided by the trusts, additional customer surcharges, and potential funds from the DOE litigation are all required to cover fully the decommissioning costs. The costs of decommissioning these sites and the adequacy of the trust funds could be affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from customers, and
- changes in decommissioning technology, regulations, estimates, or assumptions.
Based on current projections, the current level of funds provided by the trusts is not adequate to fund fully the decommissioning of Big Rock or Palisades. This is due in part to the DOE's failure to accept the spent nuclear fuel on schedule and lower returns on the trust funds. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation. We are also seeking additional relief from the MPSC. For additional details on nuclear decommissioning, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Plant Decommissioning" and "Nuclear Matters."
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of operations, capital expenditures, contractual obligations, debt maturities, working capital needs, and collateral requirements. During the summer months, we purchase natural gas and store it for resale primarily during the winter heating season. The market price for natural gas has increased. Although our natural gas purchases are recoverable from our customers, the amount paid for natural gas stored as inventory could require additional liquidity due to the timing of the cost recoveries. In addition, a few of our commodity suppliers have requested nonstandard payment terms or other forms of assurances, including margin calls, in connection with maintenance of ongoing deliveries of gas and electricity.
Our current financial plan includes controlling our operating expenses and capital expenditures and evaluating market conditions for financing opportunities. We believe our current level of cash and access to borrowing capacity in the capital markets, along with anticipated cash flows from operating and investing activities, will be sufficient to meet our liquidity needs through 2006. We have not made a specific determination
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concerning the reinstatement of common stock dividends. The Board of Directors may reconsider or revise its dividend policy based upon certain conditions, including our results of operations, financial condition, and capital requirements, as well as other relevant factors.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2004, $725 million consolidated cash was on hand, which includes $56 million of restricted cash and $128 million from the effect of Revised FASB Interpretation No. 46 consolidation. For additional details on cash equivalents and restricted cash, see Note 1, Corporate Structure and Accounting Policies. For additional details on FASB Interpretation No. 46, see Note 16, Implementation of New Accounting Standards.
Our primary ongoing source of cash is dividends and other distributions from our subsidiaries, including proceeds from asset sales. For the year ended December 31, 2004, Consumers paid $190 million in common stock dividends and Enterprises paid $336 million in common stock dividends and other distributions to CMS Energy.
SUMMARY OF CASH FLOWS:
OPERATING ACTIVITIES:
2004: Net cash provided by operating activities was $398 million in 2004 compared to net cash used in operating activities of $250 million in 2003. The increase of $648 million primarily represents the absence, in 2004, of $560 million in pension contributions made in 2003 and the reduced effect of rising gas prices on inventory. These changes were offset partially by increases in accounts receivable due to higher gas prices and the net effect of the sale of CMS ERM's wholesale gas and power contracts in 2003 resulting from our continued focus to optimize cash flow through the sale of non-strategic assets.
2003: Net cash used in operating activities was $250 million in 2003 compared to net cash provided by operating activities of $614 million in 2002. The change of $864 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 the net effect of the sale of CMS ERM's wholesale gas and power contracts resulting from our focus on optimizing cash flow through the sale of non-strategic assets.
INVESTING ACTIVITIES:
2004: Net cash used in investing activities increased $595 million primarily due to a decrease in asset sale proceeds of $720 million and an increase in investments in unconsolidated subsidiaries of $71 million. In 2003, we sold Panhandle, Field Services, and CMS ERM's wholesale gas and power contracts. Our 2004 $71 million investment was primarily for our equity interest in Shuweihat. These changes were offset partially by a decrease in the amount of cash restricted of $308 million resulting from our improved financial condition. In 2004, $145 million in restricted cash was no longer required to be held as collateral for letters of credit.
2003: Net cash provided by investing activities decreased $626 million primarily due to a decrease in asset sale proceeds from Equatorial Guinea, Powder River, and GMS Oil & Gas of $720 million in 2002. This was
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offset by a decrease in 2003 capital expenditures of $212 million as a result of our strategic plan to reduce capital expenditures.
FINANCING ACTIVITIES:
2004: Net cash used in financing activities increased $272 million primarily due to a decrease of $232 million in net proceeds from borrowings.
2003: Net cash provided by financing activities increased $1.452 billion primarily due to an increase in net proceeds from borrowings of $988 million and net proceeds from preferred securities issuances of $272 million.
For additional details on long-term debt activity, see Note 4, Financings and Capitalization.
SUBSEQUENT FINANCING ACTIVITIES: In January 2005, we redeemed $103 million of general term notes. In January 2005, we issued $150 million of 6.30 percent Senior Notes due 2012. We used the net proceeds of $147 million to redeem the remaining general term notes and for other corporate purposes.
In January 2005, Consumers issued $250 million of 5.15 percent FMBs due 2017. Consumers used the net proceeds of $247 million to pay off its $60 million long-term bank loan, to redeem the $73 million 8.36 percent subordinated deferrable interest notes, and to redeem the $124 million 8.20 percent subordinated deferrable interest notes. The subordinated deferrable interest notes are classified as Long-term debt -- related parties on our accompanying Consolidated Balance Sheets.
OBLIGATIONS AND COMMITMENTS
CONTRACTUAL OBLIGATIONS: The following table summarizes our contractual cash obligations for each of the periods presented. The table shows the timing and effect that such obligations are expected to have on our liquidity and cash flow in future periods. The table excludes all amounts classified as current liabilities on our Consolidated Balance Sheets, other than the current portion of long-term debt and capital and finance leases. The majority of current liabilities will be paid in cash in 2005.
Long-Term Debt: The amounts in the table above represent the principal amounts due on outstanding debt obligations, current and long-term, as of December 31, 2004. For additional details on long-term debt, see Note 4, Financings and Capitalization.
Interest Payments on Long-term Debt: The amounts in the table above represent the currently scheduled interest payments on both variable and fixed rate long-term debt and long-term debt -- related parties, current and long-term. Variable interest payments are based on contractual rates in effect at December 31, 2004.
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Capital and Finance Leases: The amounts in the table above represent the minimum lease payments payable under our capital and finance leases. They are comprised mainly of the leased portion of the MCV Partnership facility, leased service vehicles, and leased office furniture.
Interest Payments on Capital and Finance Leases: The amounts in the table represent imputed interest in the capital leases and currently scheduled interest payments on the finance leases.
Operating Leases: The amounts in the table above represent the minimum noncancelable lease payments under our leases of railroad cars, certain vehicles, and miscellaneous office buildings and equipment, which are accounted for as operating leases.
Purchase Obligations: Long-term contracts for purchase of commodities and services are purchase obligations. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include:
- natural gas,
- electricity,
- coal and associated transportation, and
- electric transmission.
Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $10 million per month during 2005. 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 3, Contingencies, "Consumers' Electric Utility Rate Matters -- Power Supply Costs."
Long-term Service Agreements: These obligations of the MCV Partnership represent the cost of the current MCV Facility maintenance service agreements and cost of spare parts.
REVOLVING CREDIT FACILITIES: At December 31, 2004, CMS Energy had $194 million available, Consumers had $475 million available, and the MCV Partnership had $48 million available in secured revolving credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. For additional details on revolving credit facilities, see Note 4, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: CMS Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, letters of credit, debt guarantees, surety bonds and indemnifications. For additional details on guarantee arrangements, see Note 4, Financings and Capitalization, "FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and in "Commercial Commitments" within this section.
Non-recourse Debt: Our share of unconsolidated debt associated with partnerships and joint ventures in which we have a minority interest is non-recourse and totals $1.368 billion at December 31, 2004. The timing of the payments of non-recourse debt only affects the cash flow and liquidity of the partnerships and joint ventures. For additional details, see Note 12, Equity Method Investments.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may sell up to $325 million of certain accounts receivable. For additional details, see Note 4, Financings and Capitalization.
COMMERCIAL COMMITMENTS: Our contingent commercial commitments include guarantees, indemnities, and letters of credit. Guarantees represent our guarantees of performance, commitments, and liabilities of our consolidated and unconsolidated subsidiaries, partnerships, and joint ventures. Indemnities are agreements to reimburse other companies, such as an insurance company, if those companies have to complete our contractual performance in a third-party contract. Banks, on our behalf, issue letters of credit guaranteeing payment to a third party. Letters of credit substitute the bank's credit for ours and reduce credit risk for the third-party beneficiary. We monitor these obligations and believe it is unlikely that we would be required to perform or otherwise incur CMS-26
any material losses associated with these guarantees. Our off-balance sheet commitments at December 31, 2004, expire as follows:
- ------------------------- (a) The surety bonds are continuous in nature. The need for the bonds is determined on an annual basis.
DIVIDEND RESTRICTIONS: Our amended and restated $300 million secured revolving credit facility restricts payments of dividends on our common stock during a 12-month period to $75 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility.
Under the provisions of its articles of incorporation, at December 31, 2004, Consumers had $456 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim gas rate order, which included a $190 million annual dividend cap imposed on Consumers. For the year ended December 31, 2004, we received $190 million of common stock dividends from Consumers.
CAPITAL EXPENDITURES: We estimate that we will make the following capital expenditures, including new lease commitments, by business segments during 2005 through 2007. We prepare these estimates for planning purposes and may revise them.
- ------------------------- (a) These amounts include a portion of Consumers' 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 recent revisions to the Clean Air Act's national air quality standards.
OUTLOOK
CORPORATE OUTLOOK
During 2004, we have continued to implement a business strategy that involves improving our balance sheet and providing superior utility operations and service. This strategy is designed to generate cash to pay down debt and provide for more predictable future operating revenues and earnings.
Our primary focus with respect to our non-utility businesses has been to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets, and to improve earnings and cash flow from businesses we plan to retain. Although much of our asset sales program is complete, we still may sell certain remaining businesses that are not strategic to us. As this continues, the percentage of our future earnings relating to our larger equity method investments, including Jorf Lasfar, may increase and our total future earnings
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may depend more significantly upon the performance of those investments. For additional details, see Note 12, Equity Method Investments.
Over the next few years, we expect our business strategy to reduce parent company debt substantially, improve our credit ratings, grow earnings, restore a common stock dividend, and position the company to make new investments consistent with our strengths. In the near term, our new investments will focus principally on the utility.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: In 2004, we experienced cooler than normal summer weather. As a result, our electric deliveries in 2004, including deliveries to customers who chose to buy generation service from alternative electric suppliers, increased less than one-half of one percent over the levels experienced in 2003. In 2005, we project electric deliveries to grow almost three percent. This short-term outlook for 2005 assumes a stronger economy than in 2004 and normal weather conditions throughout the year.
Over the next five years, we expect electric deliveries to grow at an average rate of approximately two percent per year, based primarily on a steadily growing customer base and economy. This growth rate includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. This growth rate reflects a long-range expected trend of growth. Growth from year to year may vary from this trend due to customer response to fluctuations in weather conditions and changes in economic conditions, including utilization and expansion of manufacturing facilities.
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/or Clear Skies legislation compliance,
- compliance with legislative proposals that would require reductions in emissions of greenhouse gases, 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,
- recovery of our Section 10d(4) Regulatory Assets,
- effects of lost electric supply load to alternative electric suppliers, and
- status as an electric transmission customer instead of an electric transmission owner and the impact of the evolving RTO infrastructure.
Regulatory
- financial and operating effects of regulatory requirements imposed by the MISO, the FERC, state and federal regulators, or others, seeking to improve reliability of national and state transmission systems,
- inadequate regulatory response to applications for requested rate increases,
- responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel,
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- recovery of nuclear decommissioning costs. For additional details, see "Accounting for Nuclear Decommissioning Costs" within this MD&A, and
- potential for the Midwest Energy Market to develop into an active energy market in the state of Michigan and the potential derivative accounting impact. For additional details, see "Accounting for Financial and Derivative Instruments, Trading Activities, and Market Risk Information" within this MD&A.
Other
- effects of commodity fuel prices such as natural gas, oil, and coal,
- pending litigation filed by PURPA qualifying facilities, and
- other pending litigation.
For additional details about these trends or uncertainties, see Note 3, Contingencies.
ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.
Clean Air: Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for us. The Title I provisions of the Clean Air Act require significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $802 million. The key assumptions included in the capital expenditure estimate include:
- construction commodity prices, especially construction material and labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.06 percent. As of December 31, 2004, we have incurred $525 million in capital expenditures to comply with these regulations and anticipate that the remaining $277 million of capital expenditures will be made between 2005 and 2011. These expenditures include installing selective catalytic reduction technology at four of our coal-fired electric plants. In addition to modifying the coal-fired electric plants, we expect to utilize nitrogen oxide emissions allowances for years 2005 through 2009, most of which have been purchased. The cost of the allowances is estimated to average $8 million per year for 2005-2006. The need for allowances will decrease after year 2006 with the installation of emissions control technology. The cost of the allowances is accounted for as inventory. The allowance inventory is expensed as the coal-fired electric generating units emit nitrogen oxide.
The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits from the EPA. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of "routine maintenance." If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question.
The EPA has proposed a Clean Air Interstate Rule that would require additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. If implemented, this rule potentially would require expenditures equivalent to those efforts in progress to reduce nitrogen oxide emissions as required under the Title I provisions of the Clean Air Act. The rule proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent and nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two alternative sets of rules to reduce emissions of mercury from coal-fired electric plants and nickel from oil-fired electric plants. Until the proposed environmental rules are finalized, an accurate cost of compliance cannot be determined.
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Our switch to western coal as a primary fuel source has resulted in reduced plant emissions and increased our flexibility in meeting future regulatory compliance requirements. Excess sulfur dioxide allowances optimize our overall cost of regulatory compliance by delaying capital expenditures and minimizing regulatory uncertainty. Additionally, the excess sulfur dioxide allowances can be used to trade for nitrogen oxide allowances supplementing our nitrogen oxide allowance bank. Western coal has reduced our overall cost of fuel and reduced the economic impact from the recent increases in eastern coal prices.
Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, however, none have yet been enacted. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any such rules.
To the extent that greenhouse gas emission reduction rules come into effect, such mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sectors. We cannot estimate the potential effect of federal or state level greenhouse gas policy on our future consolidated results of operations, cash flows, or financial position due to the speculative nature of the policies at this time. However, we stay abreast of and engage in the greenhouse gas policy developments and will continue to assess and respond to their potential implications on our business operations.
Water: In March 2004, the EPA issued rules that govern generating plant cooling water intake systems. The new rules require significant reduction in fish killed by operating equipment. Some of our facilities will be required to comply with the new rules by 2006. We are currently studying the rules to determine the most cost-effective solutions for compliance.
For additional details on electric environmental matters, see Note 3, Contingencies, "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. The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. As of March 2005, alternative electric suppliers are providing 900 MW of generation supply to ROA customers. This amount represents 12 percent of our distribution load and an increase of 23 percent compared to March 2004. Based on current trends, we predict total load loss by the end of 2005 to be in the range of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load loss will fall within that range.
In July 2004, as a result of legislative hearings, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act. The proposals include:
- requiring that all rate classes of regulated utilities be based on cost of service,
- establishing a defined Stranded Cost calculation method,
- allowing customers who stay with or switch to alternative electric suppliers after December 31, 2005 to return to utility services, and requiring them to pay current market rates upon return,
- establishing reliability standards that all electric suppliers must follow,
- requiring utilities and alternative electric suppliers to maintain a 15 percent power reserve margin,
- creating a service charge to fund the Low Income and Energy Efficiency Fund,
- giving kindergarten through twelfth-grade schools a discount of 10 percent to 20 percent on electric rates, and
- authorizing a service charge payable by all customers for meeting Clean Air Act requirements.
This legislation was not enacted before the end of the 2003-2004 legislative session. We anticipate that some or all of the bills may be reintroduced in the 2005-2006 legislative session. We cannot predict the outcome of these legislative proceedings.
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Implementation Costs: Applications for recovery of $7 million of implementation costs for 2002 and $1 million for 2003 are pending MPSC approval. In September 2004, the ALJ issued a Proposal for Decision recommending full recovery of these costs.
We are also pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million of Alliance RTO development costs. Included in this amount is $5 million pending approval by the MPSC as part of our 2002 implementation costs application. The FERC has denied our request for reimbursement and we are appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. Although we believe these implementation costs are fully recoverable in accordance with the Customer Choice Act, we cannot predict the amount, if any, the MPSC or the FERC will approve as recoverable.
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze and rate cap periods, including the cost of money. In October 2004, we filed an application with the MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets for the period June 2000 through December 2005 consisting of:
- capital expenditures in excess of depreciation,
- Clean Air Act costs,
- other expenses related to changes in law or governmental action incurred during the rate freeze and rate cap periods, and
- the associated cost of money through the period of collection.
Of the $628 million, $152 million relates to the cost of money. In March 2005, the MPSC Staff filed testimony recommending the MPSC approve recovery of approximately $323 million. We cannot predict the amount, if any, the MPSC will approve as recoverable.
Rate Caps: The Customer Choice Act imposes certain limitations on electric rates that could result in our inability to collect our full cost of conducting business from electric customers. Rate caps are effective through December 31, 2005 for residential customers. As a result, we may be unable to maintain our profit margins in our electric utility business during the rate cap period. In particular, if we need to purchase power supply from wholesale suppliers while retail rates are capped, the rate restrictions may preclude full recovery of purchased power and associated transmission costs.
Power Supply Costs: To reduce the risk of high electric prices during peak demand periods and to achieve our reserve margin target, we employ a strategy of purchasing electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We are currently planning for a reserve margin of approximately 11 percent for summer 2005, or supply resources equal to 111 percent of projected summer peak load. Of the 2005 supply resources target of 111 percent, we expect to meet approximately 102 percent from our electric generating plants and long-term power purchase contracts, and approximately 9 percent from short-term contracts, options for physical deliveries, and other agreements. We have purchased capacity and energy contracts partially covering the estimated reserve margin requirements for 2005 through 2007. As a result, we have recognized an asset of $12 million for unexpired capacity and energy contracts as of December 31, 2004.
PSCR: The PSCR process assures recovery of all reasonable and prudent power supply costs actually incurred by us. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from other customers. We self-implemented the proposed 2005 PSCR charge in January 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings.
Special Contracts: We entered into multi-year electric supply contracts with certain industrial and commercial customers. The contracts provide electricity at specially negotiated prices that are at a discount from
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tariff prices, but above our incremental cost of service. As of February 2005, special contracts for approximately 630 MW of load are in place, most of which are in effect through 2005. We cannot predict the amount of electric load from these customers that will continue with our electric service after their contracts expire.
Transmission Costs: In May 2002, we sold our electric transmission system for $290 million to MTH. We are in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized by approximately $2 million to $3 million.
There are multiple proceedings and a proposed rulemaking pending before the FERC regarding transmission pricing mechanisms and standard market design for electric bulk power markets and transmission. The results of these proceedings and proposed rulemaking could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
In November 2004, the FERC ruled on MISO and PJM RTO "through and out" rates. Through and out rates are applied to transmission transactions when a transmission customer purchases electricity that travels through multiple transmission pricing zones. Effective December 1, 2004, regional through and out rates for transactions between the PJM RTO and the MISO were eliminated by the FERC. In that November 2004 order, the FERC conditionally accepted, for a period beginning December 1, 2004 and ending January 31, 2008, a "license plate" pricing structure. License plate pricing provides for access to the combined regional transmission systems of the PJM RTO and the MISO at a single rate, although the rate may vary based on where the customer's load is located.
The order also adopts a transitional charge from December 1, 2004 through March 31, 2006, intended to mitigate abrupt cost shifts between transmission owners and customers as a result of the pricing structure change. The manner in which these transitional charges are calculated and implemented is currently the subject of multiple disputes pending at the FERC. Based on the compliance filings with the FERC made by the MISO and PJM RTO transmission owners, the new transitional charges will not have a significant impact on our electric results of operations. However, we cannot predict the outcome of the disputes concerning these transitional charges pending at the FERC.
Transmission Market Developments: The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005. At that time, the MISO will implement a day-ahead and real-time energy market and centralized dispatch for the MISO's market participants. These changes are anticipated to ensure that load requirements in the region are met reliably and efficiently, to better manage congestion on the grid, and to produce consumer savings through the centralized dispatch of generation throughout the region. The MISO is expected to provide other functions, including long-term regional planning and market monitoring.
In addition, we are evaluating whether or not there may be impacts on electric reliability associated with changes in the composition of transmission markets. For example, Commonwealth Edison Company joined the PJM RTO in May 2004 and American Electric Power Service Corporation joined the PJM RTO in October 2004. These integrations may be creating different patterns of power flow within the Midwest area and could affect adversely our ability to provide reliable service to our customers. We are presently evaluating what financial impacts, if any, these market developments are having on our operations.
August 14, 2003 Blackout: The NERC and the U.S. and Canadian Power System Outage Task Force have released electric operations recommendations resulting from their investigation into the August 14, 2003 blackout. Few of the recommendations apply directly to us, since we are not a transmission owner. However, the recommendations could result in increased transmission costs to us and require upgrades to our distribution system. We cannot quantify the financial impact of these recommendations at this time.
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For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, "Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric Utility Rate Matters."
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to increase our retail electric base rates. The electric rate case filing requests an annual increase in revenues of approximately $320 million. The primary reasons for the request are increased system maintenance and improvement costs, Clean Air Act related expenditures, and employee pension costs. A final order from the MPSC on our electric rate case is expected in late 2005. If approved as requested, the rate increase would go into effect in January 2006 and would apply to all retail electric customers. We cannot predict the amount or timing of the rate increase, if any, which the MPSC will approve.
BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of Appeals upheld a lower court decision that requires Detroit Edison to obey a municipal ordinance enacted by the City of Taylor, Michigan. The ordinance requires Detroit Edison to bury a section of its overhead power lines at its own expense. Detroit Edison has filed an appeal with the Michigan Supreme Court. Unless overturned by the Michigan Supreme Court, the decision could encourage other municipalities to adopt similar ordinances, as has occurred or is being discussed in a few municipalities in Consumers' service territory. If incurred, we would seek recovery of these costs from our customers, subject to MPSC approval. This case has potentially broad ramifications for the electric utility industry in Michigan; however, at this time, we cannot predict the outcome of this matter.
OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES
NUCLEAR MATTERS:
Big Rock: Dismantlement of plant systems is essentially complete and demolition of the remaining plant structures has begun. The restoration project is on schedule to return approximately 530 acres of the site, including the area formerly occupied by the nuclear plant, to a natural setting for unrestricted use in mid-2006. An additional 30 acres, the area where seven transportable dry casks loaded with spent nuclear fuel and an eighth cask loaded with high-level radioactive waste material are stored, will be returned to a natural state by the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.
Palisades: In August 2004, the NRC completed its mid-cycle plant performance assessment of Palisades. The assessment for Palisades covered the first half of 2004. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. As of December 2004, all inspection findings were classified as having very low safety significance and all performance indicators show performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through March 2006.
The amount of spent nuclear fuel at Palisades exceeds the plant's temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of December 31, 2004, we have loaded 22 dry casks with spent nuclear fuel. For additional information on disposal of spent nuclear fuel, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Matters."
In September 2004, we announced that we will seek a license renewal for the Palisades plant. The plant's current license from the NRC expires in 2011. NMC, which operates the facility, will apply for a 20-year license renewal for the plant on behalf of Consumers. The Palisades renewal application is scheduled to be filed by the end of the first quarter of 2005.
We have authorized the purchase of a replacement reactor vessel closure head. The replacement head is being manufactured and scheduled to be installed in 2007. Palisades, like many other nuclear plants, has experienced cracking in reactor head nozzle penetrations. Repairs to two nozzles were made in 2004. The replacement head nozzles will be manufactured from materials less susceptible to cracking and should minimize inspection and repair costs after replacement.
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
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was served on us by the MPSC in April 2003. The complaint asks the MPSC to initiate a generic investigation and contested case to review all facts and issues concerning costs associated with spent nuclear fuel storage and disposal. The complaint seeks a variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service Corporation. The complaint states that amounts collected from customers for spent nuclear fuel storage and disposal should be placed in an independent trust. The complaint also asks the MPSC to take additional actions. In May 2003, Consumers and other named utilities each filed motions to dismiss the complaint. We are unable to predict the outcome of this matter.
GAS UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an average rate of less than one percent per year. Actual gas deliveries in future periods may be affected by:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the MPSC for a Certificate of Public Convenience and Necessity to construct a 25-mile gas transmission pipeline in northern Oakland County. The project is necessary to meet estimated peak load beginning in the winter of 2005 through 2006. In December 2004, the MPSC approved a settlement agreement authorizing us to construct and operate the pipeline. Construction is expected to begin late spring of 2005.
In October 2004, we filed an application with the MPSC for a Certificate of Public Convenience and Necessity to construct a 10.8-mile gas transmission pipeline in northwestern Wayne County. The project is necessary to meet the projected capacity demands beginning in the winter of 2007. If we are unable to construct the pipeline, we will need to pursue more costly alternatives or curtail serving the system's load growth in that area.
GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial results and conditions. These trends or uncertainties could have a material impact on revenues or income from gas operations. The trends and uncertainties include:
Regulatory
- inadequate regulatory response to applications for requested rate increases,
- response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, and
- proposed distribution pipeline integrity rules and mandates.
Environmental
- potential environmental remediation costs at a number of sites, including sites formerly housing manufactured gas plant facilities.
Other
- transmission pipeline integrity mandates, maintenance and remediation costs, and
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- other pending litigation.
GAS TITLE TRACKING FEES AND SERVICES: On February 14, 2005, the FERC issued its latest order involving Consumers' Gas Title Transfer Tracking Fees and Services. In doing so, the FERC agreed with us that such orders only apply to a title transfer tracking fee charged and collected in connection with the Consumers' FERC blanket transportation service. Because of the newly stated limits on what fees are subject to refund, we believe that if any such refunds are ultimately required, they will not be material.
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs for prudency in an annual reconciliation proceeding.
The following table summarizes our GCR reconciliation filings with the MPSC. For additional details, see Note 3, Contingencies, "Consumers' Gas Utility Rate Matters -- Gas Cost Recovery."
GAS COST RECOVERY RECONCILIATION
Net over-recovery amounts included in the table above include refunds that we received from our suppliers that are required to be refunded to our customers.
GCR year 2003-2004: In February 2005, the MPSC approved a settlement agreement that resulted in a credit to our GCR customers for a $28 million over-recovery, plus $3 million interest, using a roll-in refund methodology. The roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan year.
GCR plan for year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
GCR plan for year 2005-2006: In December 2004, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2005 through March 2006. Our request proposes using a GCR factor consisting of:
- a base GCR factor of $6.98 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future events.
The GCR factor can be adjusted monthly, provided it remains at or below the current ceiling price. The quarterly adjustment mechanism allows an increase in the GCR ceiling price to reflect a portion of cost increases if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. In December 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes.
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On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon our agreement to:
- achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached,
- make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted,
- refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate,
- prepare and file annual reports that address certain issues identified in the order, and
- file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect).
On October 15, 2004, we agreed to these commitments.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003, the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case.
In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case. The October 2004 order requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. The MPSC also directed us to undertake a study to determine why our removal costs are in excess of those of other regulated Michigan natural gas utilities and file a report with the MPSC Staff on or before December 31, 2005.
In February 2005, we requested a delay in the filing date for the next depreciation case until after the MPSC considers the removal cost study, and after the MPSC issues an order in a pending case relating to asset retirement obligation accounting.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. We expect our remaining remedial action costs to be between $37 million and $90 million. We expect to fund most of these costs through insurance proceeds and through the MPSC approved rates charged to our customers. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs. For additional details, see Note 3, Contingencies, "Consumers' Gas Utility Contingencies -- Gas Environmental Matters."
OTHER CONSUMERS' OUTLOOK
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $10 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund (net of approximately $16 million of deferred expenses) has not been recognized in 2004 earnings.
COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees are represented by the Utility Workers of America Union. The Union represents Consumers' operating, maintenance, and construction employees and our call center employees. The collective bargaining agreement with the Union for our operating, maintenance, and construction employees will expire on June 1, 2005 and negotiations for a new agreement is CMS-36
underway currently. The collective bargaining agreement with the Union for our call center employees will expire on August 1, 2005.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to continue the restructuring of our IPP business with the objective of narrowing the focus of our operations to primarily North America, South America, and the Middle East/North Africa. We will continue to sell designated assets and investments that are under-performing or are not consistent with this focus. In February 2005, we sold our interest in GVK for $20 million.
CMS ERM: CMS ERM has streamlined its portfolio in order to reduce business risk and outstanding credit guarantees. Our future activities will be centered on fuel procurement activities and merchant power marketing in such a way as to optimize the earnings from our IPP generation assets.
CMS GAS TRANSMISSION: CMS Gas Transmission has completed its plan to sell the majority of its international assets and businesses. Future operations will be conducted mainly in Michigan and South America.
GasAtacama: On March 24, 2004, the Argentine Government authorized the restriction of exports of natural gas to Chile, giving priority to domestic demand in Argentina. This restriction could have a detrimental effect on GasAtacama's earnings since GasAtacama's gas-fired electric generation plant is located in Chile and uses Argentine gas for fuel. From April through December 2004, Bolivia agreed to export 4 million cubic meters of gas per day to Argentina, which allowed Argentina to minimize its curtailments to Chile.
Argentina and Bolivia extended the term of that agreement through December 31, 2005. With the Bolivian gas supply, Argentina relaxed its export restrictions to GasAtacama, currently allowing GasAtacama to receive approximately 50 percent of its contracted gas quantities at its electric generation plant. At this point in time, it is not possible to predict the outcome of these events and their effect on the earnings of GasAtacama.
Other: 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 contingent note of Cantera Natural Gas, Inc., which is not included in our consolidated financial statements. The contingent note is payable to CMS Energy for up to $50 million, subject to the financial performance of the Fort Union and Bighorn natural gas gathering systems from 2004 through 2008. The financial performance is dependent primarily on the number of new wells connected, transportation volumes, and revenue with certain EBITDA thresholds required to be achieved in order for us to receive payments on the contingent note. It has not been determined for 2004 results whether we will receive a payment on the note in 2005.
UNCERTAINTIES: The results of operations and the financial position of our diversified energy businesses may be affected by a number of trends or uncertainties. Those that could have a material impact on our income, cash flows, or balance sheet and credit improvement include:
- our ability to sell or to improve the performance of assets and businesses in accordance with our business plan,
- changes in exchange rates or in local economic or political conditions, particularly in Argentina, Venezuela, Brazil, and the Middle East,
- changes in foreign laws or in governmental or regulatory policies that could reduce significantly the tariffs charged and revenues recognized by certain foreign subsidiaries, or increase expenses,
- imposition of stamp taxes on South American contracts that could increase project expenses substantially,
- impact of any future rate cases, FERC actions, or orders on regulated businesses,
- impact of ratings downgrades on our liquidity, operating costs, and cost of capital,
- impact of changes in commodity prices and interest rates on certain derivative contracts that do not qualify for hedge accounting and must be marked to market through earnings, and
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- changes in available gas supplies or Argentine government regulations that could restrict natural gas exports to our GasAtacama generating plant.
OTHER OUTLOOK
LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an investigation by the DOJ regarding round-trip trading transactions by CMS MST. Additionally, we are named as a party in various litigation matters including, but not limited to, a shareholder derivative lawsuit, a securities class action lawsuit, a class action lawsuit alleging ERISA violations, and several lawsuits regarding alleged false natural gas price reporting and price manipulation. For additional details regarding these investigations and litigation, see Note 3, Contingencies.
NEW ACCOUNTING STANDARDS
For a discussion of new pronouncements, see Note 16, Implementation of New Accounting Standards.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to expense the grant date fair value of employee stock options and similar awards. The Statement also clarifies and expands SFAS No. 123's guidance in several areas, including measuring fair value, classifying an award as equity or as a liability, and attributing compensation cost to reporting periods.
In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to require that excess tax benefits related to the excess of the tax deductible amount over the compensation cost recognized be classified as a financing cash inflow rather than as a reduction of taxes paid in operating cash flows.
This Statement is effective for us as of the beginning of the third quarter of 2005. We adopted the fair value method of accounting for share-based awards effective December 2002, and therefore, expect this Statement to have an insignificant impact on our results of operations when it becomes effective.
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CMS ENERGY CORPORATION MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
CMS Energy's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, CMS Energy's management concluded that its internal control over financial control reporting was effective as of December 31, 2004.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
CMS Energy's management's assessment of the effectiveness of CMS Energy's internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, who audited the consolidated financial statements of CMS Energy included in this Form 10-K. Ernst & Young LLP's attestation report on CMS Energy's management's assessment of internal control over financial reporting follows this report.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of CMS Energy Corporation
We have audited management's assessment, included in MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that CMS Energy Corporation (a Michigan Corporation) and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CMS Energy Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the company's internal control over financial reporting based on our audit. We did not examine the effectiveness of internal control over financial reporting of Midland Cogeneration Venture Limited Partnership, a 49% owned variable interest entity which has been consolidated pursuant to Revised Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities", whose financial statements reflect total assets and revenues constituting 12% and 12%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004. The effectiveness of Midland Cogeneration Venture Limited Partnership's internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the effectiveness of Midland Cogeneration Venture Limited Partnership's internal control over financial reporting, is based solely on the report of the other auditors.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit and the report of the other auditors provide a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, based on our audit and the report of the other auditors, management's assessment that CMS Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, based on our audit and the report of the other auditors, CMS Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CMS Energy Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income (loss), common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2004 and our report dated March 7, 2005 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Detroit, Michigan March 7, 2005
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MCV MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
MCV's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting of MCV. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
MCV's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of MCV; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of MCV are being made only in accordance with authorizations of management and the Management Committee of MCV; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of MCV's assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. Our system contains self-monitoring mechanisms, and actions are taken to correct deficiencies as they are identified.
MCV management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the framework in "Internal Control -- Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that MCV's system of internal control over financial reporting was effective as of December 31, 2004. MCV management's assessment of the effectiveness of MCV's internal control over financial reporting has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
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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.
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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
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CMS ENERGY CORPORATION
The accompanying notes are an integral part of these statements.
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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.
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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: CMS Energy is an integrated energy company with a business strategy focused primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international diversified energy businesses, including independent power production and natural gas transmission, storage and processing. We manage our businesses by the nature of services each provides and operate principally in three business segments, electric utility, gas utility, and enterprises.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the accounts of CMS Energy, Consumers, Enterprises, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with Revised FASB Interpretation No. 46. The primary beneficiary of a variable interest entity is the party that absorbs or receives a majority of the entity's expected losses or expected residual returns or both as a result of holding variable interests, which are ownership, contractual, or other economic interests. In accordance with Revised FASB Interpretation No. 46, in 2003, we consolidated three Michigan electric generating plants and in 2004, we consolidated the MCV Partnership and the FMLP. For additional details, see Note 16, Implementation of New Accounting Standards. We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. Intercompany transactions and balances have been eliminated.
USE OF ESTIMATES: We prepare our consolidated financial statements in conformity with U.S. generally accepted accounting principles. 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 consolidated financial statements when it is probable that a loss will be incurred in the future as a result of a current event, and when an amount can be reasonably estimated. We have used this accounting principle to record estimated liabilities as discussed in Note 3, Contingencies.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the transportation, processing, and storage of natural gas when services are provided. 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.
ACCRETION EXPENSE: CMS ERM has entered into prepaid sales arrangements to provide natural gas to various entities over periods of up to 12 years at predetermined price levels. CMS ERM has established a liability for these outstanding obligations equal to the discounted present value of the contracts, and has hedged its exposures under these arrangements. The amounts recorded as liabilities on our Consolidated Balance Sheets are guaranteed by Enterprises. As CMS ERM fulfills its obligations under the contracts, it recognizes revenues upon the delivery of natural gas, records a reduction to the outstanding obligation, and recognizes accretion expense.
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.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
At December 31, 2004, our restricted cash on hand was $56 million. Restricted cash dedicated for repayment of Securitization bonds is classified as a current asset as the payments on the related Securitization bonds occur within one year.
COST METHOD INVESTMENTS: At December 31, 2004, our cost method investments totaled $22 million, substantially all of which were evaluated for impairment in 2004. We periodically reevaluate the fair value of our cost method investments if there are specific events or changes in circumstances that may have a significant adverse effect on the fair value of our investments.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the weighted average number of shares of common stock and dilutive potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive stock options, warrants and convertible securities. The effect on number of shares of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable. For earnings per share computation, see Note 5, Earnings Per Share.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities using SFAS No. 115. Debt and equity securities classified as available-for-sale are reported at fair value determined from quoted market prices. Debt and equity securities classified as held-to-maturity are reported at cost. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary.
Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our earnings or cash flows.
For additional details regarding financial instruments, see Note 6, Financial and Derivative Instruments.
FOREIGN CURRENCY TRANSLATION: Our subsidiaries and affiliates whose functional currency is not the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect at the end of the fiscal period. We translate revenue and expense accounts of such subsidiaries and affiliates into U.S. dollars at the average exchange rates that prevailed during the period. The gains or losses that result from this process are shown in the stockholders' equity section on our Consolidated Balance Sheets. For subsidiaries operating in highly inflationary economies, the U.S. dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those that are hedged, are included in determining net income.
GAS INVENTORY: We use the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities.
GENERATING PLANT FUEL STOCK INVENTORY: We use the weighted average cost method for valuing coal inventory and classify these costs as generating plant fuel stock on our Consolidated Balance Sheets. The MCV Partnership's natural gas inventory is also included in this category, stated at the lower of cost or market and valued using the last-in, first-out ("LIFO") method.
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 13, 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 investment or asset exceeds its estimated
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
undiscounted future 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 represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements. We depreciate utility property using straight-line rates approved by the MPSC. The composite depreciation rates for our properties are:
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on the quantity of heat produced for electric generation. For nuclear fuel used after April 6, 1983, we charge certain disposal costs to nuclear fuel expense, recover these costs through electric rates, and remit them to the DOE quarterly. We elected to defer payment for disposal of spent nuclear fuel burned before April 7, 1983. As of December 31, 2004, we have recorded a liability to the DOE of $141 million, including interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. The amount of this liability, excluding a portion of interest, was recovered through electric rates. For additional details on disposal of spent nuclear fuel, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Matters."
OTHER INCOME AND OTHER EXPENSE: The following tables show the components of Other income and Other expense:
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at original cost when placed into service. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost is charged to accumulated depreciation. The cost of removal, less salvage, is recorded as a regulatory liability. For additional details, see Note 8, Asset Retirement Obligations. An allowance for funds used during
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 2004 and 2003, was as follows:
- ------------------------- (a) Capital leases presented in this table are gross amounts. Amortization of capital leases was $49 million in 2004 and $38 million in 2003.
(b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2004 and $23 million at December 31, 2003, which is not subject to depreciation.
(c) Accumulated depreciation, depletion, and amortization is made up of $5.665 billion from our public utility plant assets and $450 million from other plant assets as of December 31, 2004 and $4.417 billion from public utility plant assets and $425 million from other plant assets as of December 31, 2003.
(d) Included in net property, plant and equipment are intangible assets related primarily to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization life for software development costs is seven years, leasehold improvements is over the life of the lease and other intangible
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
amortization lives range from 50 to 105 years. Intangible assets at December 31, 2004 and 2003 were as follows:
Pretax amortization expense related to these intangible assets was $21 million for the year ended December 31, 2004, $21 million for the year ended December 31, 2003, and $20 million for the year ended December 31, 2002. Intangible assets amortization is forecasted to range from $10 million to $21 million per year over the next five years.
(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 (loss) for the years presented.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
RELATED-PARTY TRANSACTIONS: We received income from related parties as follows:
We recorded expense from related parties as follows:
- ------------------------- (a) At December 31, 2003, we consolidated the T.E.S. Filer City Station Limited Partnership, Grayling Generating Station Limited Partnership, and Genessee Power Station Limited Partnership into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 16, Implementation of New Accounting Standards.
(b) In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 16, Implementation of New Accounting Standards.
(c) We issued Trust Preferred Securities through several CMS Energy and 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 our Consolidated Statements of Income (Loss), Interest on Long-term debt -- related parties to the trusts holding the Trust Preferred Securities. For additional information on our affiliated Trust Preferred Securities companies, see Note 16, Implementation of New Accounting Standards.
TRADE RECEIVABLES: We record our accounts receivable at fair value. Accounts deemed uncollectible are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums, discounts, and expenses incurred in connection with the issuance of long-term debt and amortize those costs ratably over the terms of the debt issues. Any refinancing costs are charged to expenses as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and expenses and amortize them ratably over the terms of the newly issued 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.
We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets. We expect to recover these costs through rates over periods of up
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
to 14 years. We recognized an OPEB transition obligation in accordance with SFAS No. 106 and established a regulatory asset for the amount that we expect to recover in rates over the next eight years.
- ------------------------- (a) At December 31, 2004, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.677 billion of regulatory assets as non-current regulatory assets. At December 31, 2003, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.086 billion of regulatory assets as non-current regulatory assets. At December 31, 2004 and December 31, 2003, all of our regulatory liabilities represented non-current regulatory liabilities.
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 $219 million for the year ended December 31, 2004 and $939 million for the year ended December 31, 2003.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
At December 31, 2004, we no longer have assets that qualify as "held for sale." At December 31, 2003, "Assets held for sale" included Parmelia, Bluewater Pipeline, and our investment in the American Gas Index fund. The major classes of assets and liabilities held for sale on our Consolidated Balance Sheets are as follows:
DISCONTINUED OPERATIONS
We have discontinued the following operations:
- ------------------------- (a) In August 2004, we sold our Parmelia business and our interest in Goldfields, which did not meet the criteria for discontinued operations, to APT for A$204 million (approximately $147 million in U.S. dollars). The $10 million ($6 million after-tax) gain on the sale of Parmelia includes a $3 million ($2 million after-tax) foreign currency translation loss.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following amounts are reflected in the Consolidated Statements of Income (Loss), in the Gain (Loss) From Discontinued Operations line:
The gain (loss) from discontinued operations includes a reduction in asset values, a provision for anticipated closing costs, and a portion of CMS Energy's interest expense. Interest expense of less than $1 million for 2004, $22 million for 2003, and $71 million for 2002 has been allocated based on a ratio of the expected proceeds for the asset to be sold divided by CMS Energy's total capitalization of each discontinued operation multiplied by CMS Energy's interest expense.
OTHER ASSET SALES
Our other asset sales include the following assets. The impacts of these sales are included in Gain (loss) on asset sales, net in our Consolidated Statements of Income (Loss).
For the year ended December 31, 2004, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations:
- ------------------------- (a) In April 2004, we and our partners sold the 2,000 MW Loy Yang power plant and adjacent coal mine in Victoria, Australia for about A$3.5 billion ($2.6 billion in U.S. dollars), including A$145 million for the project equity. Our share of the proceeds, net of transaction costs and closing adjustments, was $44 million. In anticipation of the sale, we recorded an impairment in the first quarter, as discussed in "Asset Impairments" within this Note.
(b) In May 2004, we sold our interest in the American Gas Index fund for $7 million.
(c) In August 2004, we sold our interest in Goldfields and our Parmelia business, a discontinued operation, to APT for A$204 million (approximately $147 million in U.S. dollars). The $45 million ($29 million after-
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
tax) gain on the sale of Goldfields includes a $9 million ($6 million after-tax) foreign currency translation gain.
(d) In December 2004, we sold land in Moapa, Nevada for $3 million.
For the year ended December 31, 2003, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations:
For the year ended December 31, 2002, we sold the following assets that did not meet the definition of, and therefore were not reported as, discontinued operations:
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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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The table below summarizes our asset impairments:
- ------------------------- (a) In the first quarter of 2004, an impairment charge was recorded to recognize the reduction in fair value as a result of the sale of Loy Yang, completed in April 2004, which included a cumulative net foreign currency translation loss of approximately $110 million.
(b) In September 2003, we wrote down our investment in CMS Electric and Gas' Venezuelan electric distribution utility to reflect fair value. The impairment was based on estimates of the utility's future cash flows, incorporating certain assumptions about Venezuela's regulatory, political, and economic environment.
(c) In December 2004, we recorded impairment charges to adjust our carrying value to fair market value as a result of the planned sales of our investments in GVK and SLAP. We closed on the sale of GVK in February 2005. We expect the sale of SLAP to close in the first quarter of 2005.
(d) DIG's reduced valuation was primarily a reflection of the unfavorable terms of its power purchase agreement.
(e) In 2003, we determined that the fair values of certain equity investments at CMS Generation were lower than their carrying amount, and that these declines in value were other than temporary. Therefore, in accordance with APB No. 18, we recognized an impairment charge of $16 million ($11 million, net of tax).
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
RESTRUCTURING AND OTHER COSTS
In June 2002, we announced a series of initiatives to reduce our annual operating costs.
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, 2003, and 2004:
3: CONTINGENCIES
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 implemented, the recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of securities class action complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates. The complaints were filed as purported class actions in the United States District Court for the Eastern District of Michigan, by shareholders who allege that they purchased CMS Energy's securities during a purported class period. These cases were later consolidated by the court. The plaintiffs generally seek 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 the individual defendants filed motions to dismiss on June 21, 2004. The judge issued an opinion and order dated January 7, 2005, granting the motion to dismiss for Consumers and three of the individual defendants, but denying the motions to dismiss for CMS Energy and the 13 remaining individual defendants.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CMS Energy and the individual defendants will defend themselves vigorously but cannot predict the outcome of this litigation.
DEMAND FOR ACTION AGAINST OFFICERS AND DIRECTORS: In May 2002, the Board of Directors of CMS Energy received a demand, on behalf of a shareholder of CMS Energy Common Stock, that it commence civil actions (i) to remedy alleged breaches of fiduciary duties by certain CMS Energy officers and directors in connection with round-trip trading by CMS MST, and (ii) to recover damages sustained by CMS Energy as a result of alleged insider trades alleged to have been made by certain current and former officers of CMS Energy and its subsidiaries. In December 2002, two new directors were appointed to the Board. The Board formed a special litigation committee in January 2003 to determine whether it is in CMS Energy's best interest to bring the action demanded by the shareholder. The disinterested members of the Board appointed the two new directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation committee, CMS Energy was served with a derivative complaint filed on behalf of the shareholder in the Circuit Court of Jackson County, Michigan in furtherance of his demands. 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 were filed in July 2002 in United States District Court for the Eastern District of Michigan and were later consolidated by the court. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge issued an opinion and order dated December 27, 2004, conditionally granting plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than late in 2005. CMS Energy and Consumers will defend themselves vigorously but cannot predict the outcome of this litigation.
GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified appropriate regulatory and governmental agencies that some employees at CMS MST and CMS Field Services appeared to have provided inaccurate information regarding natural gas trades to various energy industry publications which compile and report index prices. CMS Energy is cooperating with an ongoing investigation by the DOJ regarding this matter. CMS Energy is unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation will have on its business. The CFTC filed a civil injunctive action against two former CMS Field Services employees in Oklahoma federal district court on February 1, 2005. The action alleges the two engaged in reporting false natural gas trade information, and the action seeks to enjoin such acts, compel compliance with the Commodities Exchange Act, and impose monetary penalties.
BAY HARBOR: Certain subsidiaries of CMS Energy participated in the development of Bay Harbor, a residential/commercial real estate project on the site of a discontinued cement and quarry operation near Petoskey, Michigan. As part of the development, which went forward under an agreement with the MDEQ, a golf course was constructed over several abandoned cement kiln dust piles (CKD piles), leftover from the former cement plant operation. Another former CKD area has been converted into a park. Part of the agreement with the MDEQ required the construction of a water collection system to recover seep water from one of the CKD piles. In 2002, CMS Energy sold its interests in Bay Harbor, but retained its obligations under previous environmental indemnifications entered into at the inception of the project.
From January to September 2004, the seep collection system was down for maintenance and/or awaiting permission to restart from the City of Petoskey. In September 2004, the MDEQ issued a notice of noncompliance (NON), after finding high pH-seep water in Lake Michigan adjacent to the project. The MDEQ also found higher than acceptable levels of heavy metals, including mercury, in the seep water.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Coincident with the MDEQ inspections, the EPA also assigned an inspector to the site. In November 2004, the EPA issued a Notice of Potential Liability under the Comprehensive Environmental Response, Compensation, and Liability Act, and initiated discussions with the MDEQ, CMS Energy and other parties, toward arriving at a suitable administrative consent order to address problems at Bay Harbor.
In February 2005, CMS Energy signed an Administrative Order on Consent (AOC) with the EPA and the EPA has executed the AOC. Under the AOC, CMS Energy is generally obligated, among other things, to: (i) engage in measures to restrict access to seep areas, install methods to interrupt the flow of seep water to Lake Michigan, and take other measures as may be required by the EPA under an approved plan; (ii) investigate and study the extent of hazardous substances at the site, evaluate alternatives to address a long-term remedy, and issue a report of the investigation and study; and (iii) within 120 days after EPA approval of the investigation report, enter into an enforceable agreement with the MDEQ to address a long-term remedy under certain criteria set forth in the AOC.
Several parties have issued demand letters to CMS Energy claiming breach of the indemnification provisions, making requests for payment of their expenses related to the NON, and/or claiming damages to property or personal injury with regard to the matter. CMS Energy responded to the indemnification claims by stating that it had not breached its indemnity obligations, it will comply with the indemnities, it has restarted the seep water collection facility and it has responded to the NON. CMS Energy will defend vigorously any property damage and personal injury claims, and has reserved all rights and defenses.
Based on preliminary studies, CMS Energy has identified several remediation options. The estimated potential capital and near-term expenditures for these options range from $25 million to $40 million, with continuing yearly operating and maintenance expenses ranging from $0.8 million to $1.6 million. Final remediation and resulting claims against third parties for reimbursement of remediation costs could increase or decrease these amounts. CMS Energy has recorded a liability for its obligations associated with this matter in the amount of $45 million, with a resultant charge to its income statement of $29 million, net of deferred income taxes, in the fourth quarter of 2004, reflecting CMS Energy's current best estimate of both the capital and near-term costs as well as the present value of continuing future operating costs.
An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy's financial condition and liquidity and could negatively impact CMS Energy's financial results. CMS Energy cannot predict the ultimate cost or outcome of this matter.
CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.
Clean Air: The EPA and the state regulations require us to make significant capital expenditures estimated to be $802 million. As of December 31, 2004, we have incurred $525 million in capital expenditures to comply with the EPA regulations and anticipate that the remaining $277 million of capital expenditures will be made between 2005 and 2011.
The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits from the EPA. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of "routine maintenance." If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question.
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In addition to modifying the coal-fired electric plants, we expect to utilize nitrogen oxide emissions allowances for years 2005 through 2009, most of which have been purchased. The cost of the allowances is estimated to average $8 million per year for 2005-2006. The need for allowances will decrease after year 2006 with the installation of emissions control technology.
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, 2004, we have recorded a liability for the minimum amount of our estimated Superfund liability.
In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at the Ludington Pumped Storage facility. We removed and replaced part of the PCB material. We have proposed a plan to deal with the remaining materials and are awaiting a response from the EPA.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit alleges that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. In February 2004, the Ingham County Circuit Court judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The eight plaintiff qualifying facilities have appealed the dismissal of the circuit court case to the Michigan Court of Appeals. We cannot predict the outcome of this appeal.
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms, and conditions under which retail customers are permitted to choose an electric supplier. These revised tariffs allow ROA customers, upon as little as 30 days notice to us, to return to our generation service at current tariff rates. If any class of customers' (residential, commercial, or industrial) ROA load reaches ten percent of our total load for that class of customers, then returning ROA customers for that class must give 60 days notice to return to our generation service at current tariff rates. However, we may not have capacity available to serve returning ROA customers that is sufficient or reasonably priced. As a result, we may be forced to purchase electricity on the spot market at higher prices than we can recover from our customers during the rate cap periods. We cannot predict the total amount of electric supply load that may be lost to alternative electric suppliers. As of March 2005, alternative electric suppliers are providing 900 MW of generation supply to ROA customers. This amount represents 12 percent of our distribution load and an increase of 23 percent compared to March 2004.
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ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric restructuring proceedings.
The following chart summarizes our electric restructuring filings with the MPSC:
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(a) Amount includes the cost of money through the year in which we expected to receive recovery from the MPSC and assumes recovery of Clean Air Act costs through the Section 10d(4) Regulatory Asset case.
(b) Amount includes the cost of money through the year prior to the year filed.
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze and rate cap periods, including the cost of money. The section also allows deferred recovery of expenses incurred during the rate freeze and rate cap periods that result from changes in taxes, laws, or other state or federal governmental actions. In October 2004, we filed an application with the MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets for the period June 2000 through December 2005 consisting of:
- capital expenditures in excess of depreciation,
- Clean Air Act costs,
- other expenses related to changes in law or governmental action incurred during the rate freeze and rate cap periods, and
- the associated cost of money through the period of collection.
Of the $628 million, $152 million relates to the cost of money.
As allowed by the Customer Choice Act, in January 2004, we began accruing and deferring for recovery the 2004 portion of our Section 10d(4) Regulatory Assets. In November 2004, the MPSC issued an order in Detroit Edison's general electric rate case which concluded that Detroit Edison's return of and on Clean Air Act costs incurred from June 2000 through December 2003 are recoverable under Section 10d(4). Based on the precedent set by this order, we recorded an additional regulatory asset in November 2004 for our return of and on Clean Air Act expenditures incurred from 2000 through 2003. Unless we receive an order from the MPSC to the contrary, we will continue to record additional accruals. However, certain aspects of Detroit Edison's electric rate case are different from our Section 10d(4) Regulatory Asset filing. In March 2005, the MPSC Staff filed testimony CMS-66
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recommending the MPSC approve recovery of approximately $323 million. We cannot predict the amount, if any, the MPSC will approve as recoverable. At December 31, 2004, total Section 10d(4) Regulatory Assets totaled $141 million.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system to MTH, a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc. We are in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized of approximately $2 million to $3 million.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to increase our retail electric base rates. The electric rate case filing requests an annual increase in revenues of approximately $320 million. The primary reasons for the request are increased system maintenance and improvement costs, Clean Air Act related expenditures, and employee pension costs. A final order from the MPSC on our electric rate case is expected in late 2005. If approved as requested, the rate increase would go into effect in January 2006 and would apply to all retail electric customers. We cannot predict the amount or timing of the rate increase, if any, which the MPSC will approve.
POWER SUPPLY COSTS: To reduce the risk of high electric prices during peak demand periods and to achieve our reserve margin target, we employ a strategy of purchasing electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We have purchased capacity and energy contracts partially covering the estimated reserve margin requirements for 2005 through 2007. As a result, we have recognized an asset of $12 million for unexpired capacity and energy contracts as of December 31, 2004. The total premium costs of electric capacity and energy contracts for 2004 were approximately $12 million.
PSCR: The PSCR process assures recovery of all reasonable and prudent power supply costs actually incurred by us. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from other customers. We self-implemented the proposed 2005 PSCR charge in January 2005. We estimate the increased recovery of power supply costs from commercial and industrial customers to be approximately $49 million in 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings.
OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
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 a 49 percent partnership interest in the MCV Partnership, and a 35 percent lessor interest in the MCV Facility.
In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 16, Implementation of New Accounting Standards. Our consolidated retained earnings include undistributed earnings from the MCV Partnership of $237 million at December 31, 2004 and $245 million at December 31, 2003.
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The cost that we incur under the MCV Partnership PPA exceeds the recovery amount allowed by the MPSC. We expense all cash underrecoveries directly to income. We estimate cash underrecoveries of capacity and fixed energy payments as follows:
After September 15, 2007, we expect to claim relief under the regulatory out provision in the PPA, limiting our capacity and fixed energy payments to the MCV Partnership to the amount collected from our customers. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 15, 2007 may affect negatively the earnings of the MCV Partnership and the value of our investment in the MCV Partnership.
Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. Even with the approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment.
In January 2005, the MPSC issued an order approving the RCP, with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility on the basis of natural gas market prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit our ownership interest in the MCV Partnership.
The substantial MCV Facility fuel cost savings will be used first to offset fully the cost of replacement power. Second, $5 million annually will be used to fund a renewable energy program. Remaining savings will be split between the MCV Partnership and Consumers. Consumers' direct savings will be shared 50 percent with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct savings from the RCP, after a portion is allocated to customers, will be used to offset our capacity and fixed energy underrecoveries expense. Since the MPSC has excluded these underrecoveries from the rate making process, we anticipate that our savings from the RCP will not affect our return on equity used in our base rate filings.
In January 2005, Consumers and the MCV Partnership's general partners accepted the terms of the order and implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed an application for rehearing of the MPSC order. The Attorney General also filed a claim of appeal with the Michigan Court of Appeals. We cannot predict the outcome of these appeals.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $10 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore,
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the above refund (net of approximately $16 million of deferred expenses) has not been recognized in 2004 earnings.
NUCLEAR PLANT DECOMMISSIONING: Decommissioning funding practices approved by the MPSC require us to file a report on the adequacy of funds for decommissioning at three-year intervals. We prepared and filed updated cost estimates for Big Rock and Palisades on March 31, 2004. Excluding additional costs for spent nuclear fuel storage, due to the DOE's failure to accept this spent nuclear fuel on schedule, these reports show a decommissioning cost of $361 million for Big Rock and $868 million for Palisades. Since Big Rock is currently in the process of being decommissioned, the estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars.
In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding the decommissioning trust funds for both sites. In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. The MPSC order set the annual decommissioning surcharge for Palisades at $6 million through 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability and asset retirement obligation.
BIG ROCK: Excluding the additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we are currently projecting that the level of funds provided by the trust for Big Rock will fall short of the amount needed to complete the decommissioning by $26 million. At this time, we plan to provide the additional amounts needed from our corporate funds and, subsequent to the completion of radiological decommissioning work, seek recovery of such expenditures at the MPSC. We cannot predict how the MPSC will rule on our request. The following table shows our Big Rock decommissioning activities:
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(a) Includes site restoration expenditures.
These activities had no material impact on net income. At December 31, 2004, we have an investment in nuclear decommissioning trust funds of $52 million for Big Rock. In addition, at December 31, 2004, we have charged $8 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.
PALISADES: Excluding additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we concluded that the existing surcharge for Palisades needed to be increased to $25 million annually, beginning January 1, 2006, and continue through 2011, our current license expiration date. In June 2004, we filed an application with the MPSC seeking approval to increase the surcharge for recovery of decommissioning costs related to Palisades beginning in 2006. In September 2004, we announced that we will seek a 20-year license renewal for Palisades. In January 2005, we filed a settlement agreement with the MPSC that was agreed to by four of the six parties. The settlement agreement provides for the continuation of the existing $6 million annual decommissioning surcharge through 2011 and for the next periodic review to be filed in March 2007. We are seeking MPSC approval of the settlement, under a contested settlement proceeding, but cannot predict the outcome.
At December 31, 2004, we have an investment in the MPSC nuclear decommissioning trust funds of $513 million for Palisades. In addition, at December 31, 2004, 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 8, Asset Retirement Obligations.
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NUCLEAR MATTERS:
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other utilities participated, has not been successful in producing more specific relief for the DOE's failure to accept the spent nuclear fuel.
There are two court decisions that support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. Over 60 utilities have initiated litigation in the United States Court of Claims; we filed our complaint in December 2002. In July 2004, the DOE filed an amended answer and motion to dismiss the complaint. In October 2004, we filed a response to the DOE's motion and our motion for summary judgment on liability. Oral argument has been held, and the motions are now before the Court for a decision. If our litigation against the DOE is successful, we anticipate future recoveries from the DOE. We plan to use recoveries to pay the cost of spent nuclear fuel storage until the DOE takes possession as required by law. We can make no assurance that the litigation against the DOE will be successful.
In July 2002, Congress approved and the President signed a bill designating the site at Yucca Mountain, Nevada, for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE will submit an application to the NRC sometime in 2005 for a license to begin construction of the repository. The application and review process is estimated to take several years.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $27 million in any policy year if insured losses in excess of NEIL's maximum policyholders surplus occur at our, or any other member's, nuclear facility. NEIL's policies include coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. The United States Congress enacted the Price-Anderson Act to provide financial liability protection for those parties who may be liable for a nuclear accident or incident. Part of the Price-Anderson Act's financial protection is a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed if a nuclear incident occurs at any nuclear generating facility. The maximum assessment against us could be $101 million per occurrence, limited to maximum annual installment payments of $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.
CONSUMERS' GAS UTILITY CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. We have completed initial investigations at the CMS-70
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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. We base the estimates on discounted 2003 costs using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through insurance proceeds and MPSC-approved rates. As of December 31, 2004, we have recorded a liability of $38 million, net of $44 million of expenditures incurred to date, and a regulatory asset of $65 million. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs.
In its November 2002 gas distribution rate order, the MPSC authorized us to continue to recover approximately $1 million of manufactured gas plant facilities environmental clean-up costs annually. 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 GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs for prudency in an annual reconciliation proceeding.
The following table summarizes our GCR reconciliation filings with the MPSC. Additional details related to these proceedings follow the table.
GAS COST RECOVERY RECONCILIATION
Net over-recovery amounts included in the table above include refunds that we received from our suppliers which are required to be refunded to our customers.
GCR Year 2003-2004: In February 2005, the MPSC approved a settlement agreement that resulted in a credit to our GCR customers for a $28 million over-recovery, plus $3 million interest, using a roll-in refund methodology. The roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan year.
GCR Plan for Year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR
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ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
GCR Plan for Year 2005-2006: In December 2004, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2005 through March 2006. Our request proposes using a GCR factor consisting of:
- a base GCR factor of $6.98 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future events.
The GCR factor can be adjusted monthly, provided it remains at or below the current ceiling price. The quarterly adjustment mechanism allows an increase in the GCR ceiling price to reflect a portion of cost increases if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. In December 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes.
On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon our agreement to:
- achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached,
- make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted,
- refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate,
- prepare and file annual reports that address certain issues identified in the order, and
- file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect).
On October 15, 2004, we agreed to these commitments.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003, the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case.
In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case. The October 2004 order requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. The MPSC also directed us to undertake a study to determine why our removal costs are in excess of those of other regulated Michigan natural gas utilities and file a report with the MPSC Staff on or before December 31, 2005.
In February 2005, we requested a delay in the filing date for the next depreciation case until after the MPSC considers the removal cost study, and after the MPSC issues an order in a pending case relating to asset retirement obligation accounting.
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OTHER MATTERS
COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees are represented by the Utility Workers of America Union. The Union represents Consumers' operating, maintenance, and construction employees and our call center employees. The collective bargaining agreement with the Union for our operating, maintenance, and construction employees will expire on June 1, 2005 and negotiations for a new agreement is underway currently. The collective bargaining agreement with the Union for our call center employees will expire on August 1, 2005.
OTHER CONTINGENCIES
EQUATORIAL GUINEA TAX CLAIM: CMS Energy received a request for indemnification from Perenco, the purchaser of CMS Oil and Gas. The indemnification claim relates to the sale by CMS Energy of its oil, gas, and methanol projects in Equatorial Guinea and the claim of the government of Equatorial Guinea that $142 million in taxes is owed it in connection with that sale. Based on information currently available, CMS Energy and its tax advisors have concluded that the government's tax claim is without merit, and Perenco has submitted a response to the government rejecting the claim. CMS Energy cannot predict the outcome of this matter.
GAS INDEX PRICE REPORTING LITIGATION: CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a result of false natural gas price reporting. Allegations include manipulation of NYMEX natural gas futures and options prices, price-fixing conspiracies, and artificial inflation of natural gas retail prices in California and Tennessee. CMS Energy and the other CMS defendants will defend themselves vigorously against these matters but cannot predict their outcome.
DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD) presented DIG with a change order to their construction contract and filed an action in Michigan state court claiming damages in the amount of $110 million, plus interest and costs, which DFD states represents the cumulative amount owed by DIG for delays DFD believes DIG caused and for prior change orders that DIG previously rejected. DFD also filed a construction lien for the $110 million. DIG, in addition to drawing down on three letters of credit totaling $30 million that it obtained from DFD, has filed an arbitration claim against DFD asserting in excess of an additional $75 million in claims against DFD. The judge in the Michigan state court case entered an order staying DFD's prosecution of its claims in the court case and permitting the arbitration to proceed. DFD has appealed the decision by the judge in the Michigan state court case to stay the litigation. DIG will continue to defend itself vigorously and pursue its claims. DIG cannot predict the outcome of this matter.
DIG NOISE ABATEMENT LAWSUIT: In February 2003, DIG was served with a three-count first amended complaint filed in Wayne County Circuit Court seeking damages and injunctive relief based upon allegations of excessive noise and vibration created by operation of the power plant on behalf of six named plaintiffs, all alleged to be adjacent or nearby residents or property owners and a class of "potentially thousands" who have been similarly affected. The parties entered into a settlement agreement on June 25, 2004, whereby DIG agreed to remediate the sound emitted from various pieces of plant equipment to a level below the ambient noise level and pay a substantial portion of plaintiffs' attorney fees and costs. The court entered an Order for Conditional Class Certification and Settlement Approval on August 27, 2004. No class members opted out of the settlement. DIG believes remediation is now complete at a cost of approximately $0.6 million. The parties shall seek a Final Order for Class Certification and Settlement Approval and dismissal of the action. Until such time as the entry of this Order, DIG cannot predict the final cost associated with the settlement of this matter, but expects that it will be less than $1 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
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committed to drill. A jury then awarded the plaintiffs a $7.6 million award. Terra appealed this matter to the Michigan Court of Appeals. The Michigan Court of Appeals reversed the trial court judgment with respect to the appropriate measure of damages and remanded the case for a new trial on damages. The trial judge reinstated the judgment against Terra and awarded Terra title to the minerals. Terra has appealed this judgment. Enterprises has an indemnity obligation with regard to losses to Terra that might result from this litigation.
LEONARD FIELD DISPUTE: CMS Gas Transmission is involved in various disputes related to the Leonard Storage Field in Addison Township, Michigan. The dispute centers around excess odor discharge and untimely removal of certain equipment from the Leonard Facility. CMS Gas Transmission cannot predict the outcome of this matter, and the ultimate consequence of an adverse outcome would be our inability to extract approximately 500,000 mcf of gas remaining in the Leonard Field that has a $1 million book value at December 31, 2004.
CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase agreement, CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery in La Plata, Argentina. As a result of the so-called "Emergency Laws," payments by YPF Repsol under the power purchase agreement have been converted to pesos at the exchange rate of one U.S. dollar to one Argentine peso. Such payments are currently insufficient to cover CMS Ensenada's operating costs, including quarterly debt service payments to the OPIC. Enterprises is party to a Sponsor Support Agreement pursuant to which Enterprises has guaranteed CMS Ensenada's debt service payments to OPIC up to an amount which is in dispute, but which Enterprises estimated to be approximately $9 million at June 30, 2004. Following a payment made to OPIC in July 2004, Enterprises now believes this amount to be approximately $7 million.
The Argentine commercial court granted injunctive relief to CMS Ensenada pursuant to an ex parte action, and such relief will remain in effect until completion of an arbitration on the matter, to be administered by the International Chamber of Commerce.
OTHER: CMS Generation does not currently expect to incur significant capital costs at its power facilities for compliance with current U.S. environmental regulatory standards.
In addition to the matters disclosed within this Note, Consumers and certain other subsidiaries of CMS Energy are parties to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or results of operations.
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4: FINANCINGS AND CAPITALIZATION
Long-term debt as of December 31 follows:
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(a) Contingently convertible notes. See "Contingently Convertible Securities" within this Note for further discussion of the conversion features.
(b) Redeemed $103 million in January 2005 and $117 million in February 2005.
(c) Represents the weighted average interest rate at December 31, 2004.
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(d) Maturity date uncertain.
(e) Paid off in January 2005.
FINANCINGS: The following is a summary of significant long-term debt issuances and retirements during 2004:
Issuance costs associated with the issuances of senior notes totaled $8 million and are being amortized ratably over the lives of the related debt. Issuance costs associated with the issuances of FMBs totaled $7 million and are being amortized ratably over the lives of the related debt. Call premiums associated with the Consumers debt retirements totaled $20 million and are being amortized ratably over the lives of the newly issued debt. An option payment associated with CMS Energy's retirement of the X-TRAS totaled $22 million and was charged to other interest expense in 2004.
SUBSEQUENT FINANCING ACTIVITIES: In January 2005, we redeemed $103 million of general term notes. In January 2005, we issued $150 million of 6.30 percent Senior Notes due 2012. We used the net proceeds of $147 million to redeem the remaining general term notes and for other corporate purposes.
In January 2005, Consumers issued $250 million of 5.15 percent FMBs due 2017. Consumers used the net proceeds of $247 million to pay off its $60 million long-term bank loan and to redeem the $73 million 8.36 percent and the $124 million 8.20 percent subordinated deferrable interest notes. The subordinated deferrable interest notes are classified as Long-term debt -- related parties on the accompanying Consolidated Balance Sheets.
FIRST MORTGAGE BONDS: Consumers secures its FMBs 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.
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SECURITIZATION BONDS: Securitization bonds are collateralized by certain regulatory assets. The bondholders have no recourse to our other assets. Through Consumers' rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses on the Securitization bonds. Securitization surcharges totaled $50 million annually in 2003 and 2004.
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB Interpretation No. 46. At December 31, 2004, long-term debt of the FMLP consists of:
The FMLP debt is essentially project debt secured by certain assets of the MCV Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy and Consumers.
LONG-TERM DEBT -- RELATED PARTIES: CMS Energy and Consumers each formed various statutory wholly-owned business trusts for the sole purpose of issuing preferred securities and lending the gross proceeds to ourselves. The sole assets of the trusts consist of the debentures described below. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trusts issued. We determined that we do not hold the controlling financial interest in our trust preferred security structures. Accordingly, those entities were deconsolidated as of December 31, 2003 and are reflected in Long-term debt -- related parties. The trust preferred securities were previously included in mezzanine equity.
The following is a summary of Long-term debt -- related parties as of December 31:
- ------------------------- (a) Redeemed in February 2005.
(b) Redeemed in January 2005 with available cash.
In the event of default, holders of the trust preferred securities would be entitled to exercise and enforce the trusts' creditor rights against us, which may include acceleration of the principal amount due on the debentures. We have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when
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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.
DEBT MATURITIES: At December 31, 2004, the aggregate annual maturities for long-term debt for the next five years are:
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers has FERC authorization to issue or guarantee up to $1.1 billion of short-term securities and up to $1.1 billion of short-term FMBs as collateral for such short-term securities. Consumers has FERC authorization to issue up to $1 billion of long-term securities for refinancing or refunding purposes, $1.5 billion of long-term securities for general corporate purposes, and $2.5 billion of long-term FMBs to be issued solely as collateral for other long-term securities.
REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities with banks are available as of December 31, 2004:
- ------------------------- (a) The annual interest rate on borrowings under this facility is LIBOR plus 275 basis points. Annual fees for letters-of-credit are 275 basis points on the amount outstanding. A quarterly fee of 50 basis points is payable on the average daily unused balance.
(b) This facility expires in August 2005 and may be extended annually at Consumers' option to July 31, 2007. The annual interest rate on borrowings under this facility is LIBOR plus 125 basis points. Annual fees for letters-of-credit are 125 basis points on the amount outstanding. A quarterly fee of 22.5 basis points is payable on the average daily unused balance.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we currently sell certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. We sold $304 million of receivables at December 31, 2004 and we sold $297 million of receivables at December 31, 2003. These sold amounts are excluded from accounts receivable on our Consolidated Balance Sheets. We continue to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against our other assets for failure of a debtor to pay when due and the purchaser has no right to any receivables not sold. No gain or loss has been recorded on the receivables sold and we retain no interest in the receivables sold.
Certain cash flows under our accounts receivable sales program are shown in the following table:
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DIVIDEND RESTRICTIONS: Our amended and restated $300 million secured revolving credit facility restricts payments of dividends on our common stock during a 12-month period to $75 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility.
Under the provisions of its articles of incorporation, at December 31, 2004, Consumers had $456 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in Consumers' debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim gas rate order, which included a $190 million annual dividend cap imposed on Consumers. For the year ended December 31, 2004, we received $190 million of common stock dividends from Consumers.
CAPITALIZATION: The authorized capital stock of CMS Energy consists of:
- 350 million shares of CMS Energy Common Stock, par value $0.01 per share; and
- 10 million shares of CMS Energy Preferred Stock, par value $0.01 per share.
In October 2004, we issued 32.8 million shares of our common stock. We realized net proceeds of $288 million.
PREFERRED STOCK: Our Preferred Stock outstanding follows:
- ------------------------- (a) See the "Contingently Convertible Securities" section within this Note for further discussion of the convertible preferred stock.
(b) In December 2003, we sold, in a private placement, a non-voting preferred interest in an indirect subsidiary of 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.
PREFERRED STOCK OF SUBSIDIARY: Consumers' Preferred Stock outstanding follows:
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
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issued. At the inception of a guarantee, it requires a guarantor to recognize a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provision of this Interpretation does not apply to some guarantee contracts, such as warranties, derivatives, or guarantees between either parent and subsidiaries or corporations under common control, although disclosure of these guarantees is required. For contracts that are within the recognition and measurement provision of this Interpretation, the provisions were to be applied to guarantees issued or modified after December 31, 2002.
The following table describes our guarantees at December 31, 2004:
- ------------------------- (a) The majority of this amount arises from routine provisions in stock and asset sales agreements under which we indemnify the purchaser for losses resulting from events such as failure of title to the assets or stock sold by us to the purchaser. We believe the likelihood of a loss for any remaining indemnifications to be remote.
(b) The carrying amount represents the fair market value of guarantees and indemnities recorded on our balance sheet that are entered into subsequent to January 1, 2003.
(c) Recourse provision indicates the approximate recovery from third parties including assets held as collateral.
The following table provides additional information regarding our guarantees:
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
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agreements generally are not limited in amount and, while a maximum amount of exposure cannot be identified, the probability of liability is considered remote.
We have guaranteed payment of obligations through letters of credit, indemnities, surety bonds, and other guarantees of unconsolidated affiliates and related parties of $400 million as of December 31, 2004. We monitor and approve these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with the above obligations.
CONTINGENTLY CONVERTIBLE SECURITIES: The following transactions took place in December 2004:
- we completed an exchange offering in which 82 percent of our 3.375 percent contingently convertible senior notes and 98 percent of our 4.50 percent contingently convertible preferred stock were exchanged, and
- we issued $287.5 million of 2.875 percent contingently convertible senior notes.
At December 31, 2004, the significant terms of our contingently convertible securities were as follows:
- ------------------------- (a) The notes are putable to CMS Energy by the note holders at par on July 15, 2008, 2013, and 2018 for our 3.375 percent convertible senior notes and on December 1, 2011, 2014, and 2019 for our 2.875 percent convertible senior notes. On or after December 5, 2008, we may cause the 4.50 percent convertible preferred stock to convert if the closing price of our common stock remains at or above $12.86 for 20 of any 30 consecutive trading days. The $12.86 price may be adjusted if there is a payment or distribution to our common stockholders.
(b) The securities become convertible for a calendar quarter if the price of our common stock remains at or above the trigger price for 20 of 30 consecutive trading days ending on the last trading day the previous quarter. The trigger price at which these securities become convertible is 120 percent of the conversion price, which may be adjusted if there is a payment or distribution to our common stockholders.
(c) The exchanged 3.375 percent convertible senior notes, the exchanged 4.50 percent convertible preferred stock, and all of our 2.875 percent convertible senior notes require us, if converted, to pay cash up to the principal (or par) amount of the securities and any conversion value in excess of that amount in shares of our common stock. This method of conversion is referred to as the "net share settlement" method. The remaining securities that were not exchanged retained their original settlement features.
In January 2005, the remaining 18 percent, or $27.1 million of our 3.375 percent convertible senior notes and the remaining 2 percent, or $4.5 million of our 4.50 percent convertible preferred stock were exchanged, bringing the total exchanged for both securities to 100 percent. As a result, all of our contingently convertible securities now have a net share settlement feature.
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5: EARNINGS PER SHARE
The following table presents the basic and diluted earnings per share computations.
- ------------------------- (a) Computation of diluted earnings per share for the years ended 2002 and 2003 excluded conversion of our 3.375 percent contingently convertible senior notes and our 4.50 percent contingently convertible preferred stock. Neither security was outstanding in 2002. In 2003, both securities were excluded from diluted earnings per share due to antidilution.
(b) Since the exercise price was greater than the average market price of the common stock, options and warrants to purchase 4.5 million shares of common stock were excluded from the computation of diluted earnings per share for the year ended 2004. Due to antidilution, options and warrants to purchase 6.0 million shares of common stock were excluded for the year ended 2003, and 5.1 million shares of common stock were excluded for the year ended 2002.
Contingently Convertible Securities: At its September 2004 meeting, the EITF reached a final consensus that contingently convertible instruments should be included in the diluted earnings per share computation (if dilutive) regardless of whether the market price trigger has been met. We adopted EITF Issue No. 04-8 for the period ending December 31, 2004. For additional details, see Note 16, Implementation of New Accounting Standards. Prior to our adoption of EITF Issue No. 04-8, we completed an exchange offer for our 3.375 percent contingently convertible senior notes and our 4.50 percent contingently convertible preferred stock, intended to mitigate the earnings per share impact.
The exchanged securities have the potential to dilute earnings per share to the extent that the conversion value exceeds the principal or par value.
The remaining contingently convertible securities that were not exchanged were included in the diluted earnings per share calculation using the "if-converted" method for the year ended December 31, 2004. All such
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remaining contingently convertible securities were exchanged in January 2005. For additional details, see Note 4, Financings and Capitalization, "Contingently Convertible Securities."
Trust Preferred Securities: Due to antidilution, the computation of diluted earnings per share excluded the conversion of Trust Preferred Securities into 4.2 million shares of common stock and an $8.7 million reduction of interest expense, net of tax, for the years ended 2002, 2003, and 2004. Effective July 2001, we can revoke the conversion rights if certain conditions are met.
Other: In October 2004, we issued 32.8 million shares of our common stock. For additional details, see Note 4, Financings and Capitalization.
6: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments, or other valuation techniques.
The cost and fair value of our long-term financial instruments are as follows:
- ------------------------- (a) Includes current maturities of $267 million at December 31, 2004 and $509 million at December 31, 2003. Settlement of long-term debt is generally not expected until maturity.
(b) Includes current maturities of $180 million at December 31, 2004.
(c) Nuclear decommissioning investments include cash and equivalents and accrued income totaling $11 million at December 31, 2004 and $11 million at December 31, 2003. Unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities.
(d) The fair value of available-for-sale debt securities by contractual maturity as of December 31, 2004 is as follows:
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Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $139 million as of December 31, 2004. These securities represent funds restricted primarily for future lease payments and are classified as Other assets on our Consolidated Balance Sheets. These investments have original maturity dates of approximately one year or less and, because of their short maturities, their carrying amounts approximate their fair values.
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, currency exchange rates, and equity security prices. We manage these risks using established policies and procedures, under the direction of both an executive oversight committee consisting of senior management representatives and a risk committee consisting of business-unit managers. We may use various contracts to manage these risks including swaps, options, futures, and forward contracts.
We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. Risk management contracts are classified as either non-trading or 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 through established credit policies that include performing financial credit reviews of 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 earnings as a result of counterparty nonperformance.
Contracts used to manage market risks 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 is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in fair value (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income, depending on whether the derivative qualifies for cash flow hedge accounting treatment.
For derivative instruments to qualify for hedge accounting, 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 recognized immediately 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. The ineffective portion, if any, of all hedges is recognized in earnings.
We use a combination of quoted market prices, prices obtained from external sources, such as brokers, and mathematical valuation models to determine the fair value of those contracts requiring derivative accounting. 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. In connection with the market valuation of our derivative contracts, we maintain reserves, if necessary, for credit risks based on the financial condition of counterparties.
The majority of our contracts are not subject to derivative accounting under SFAS No. 133 because they qualify for the normal purchases and sales exception, or because there is not an active market for the commodity. Certain of our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an
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active energy market in the state of Michigan and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market for the coal that we purchase. If active markets for these commodities develop in the future, we may be required to account for these contracts as derivatives, and the resulting mark-to-market impact on earnings could be material to our financial statements.
The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005, which will include day-ahead and real-time energy market information and centralized dispatch for market participants. At this time, we believe that the commencement of this market will not constitute the development of an active energy market in the state of Michigan. However, after having adequate experience with the Midwest Energy Market, we will reevaluate whether or not the activity level within this market leads to the conclusion that an active energy market exists.
Derivative accounting is required for certain contracts used to limit our exposure to commodity price risk, interest rate risk, and foreign exchange risk. The following table reflects the fair value of all contracts requiring derivative accounting:
- ------------------------- (a) The amount associated with derivative contracts held by the MCV Partnership as of December 31, 2003 represents our proportionate share of the unrealized gain on those contracts accounted for as cash flow hedges included in Accumulated other comprehensive loss. Our proportionate share of the total fair value of all derivative instruments held by the MCV Partnership as of December 31, 2003 was $51 million, and is included in Investments -- Midland Cogeneration Venture Limited Partnership on our Consolidated Balance Sheets.
The fair value of our non-trading gas contracts, interest rate risk contracts, and the derivative contracts associated with Consumers' investment in the MCV Partnership is included in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets. The fair value of the derivative contracts held by CMS ERM is included in either Price risk management assets or Price risk management liabilities on our
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Consolidated Balance Sheets. The fair value of derivative contracts associated with our equity investments is included in Investments -- Enterprises on our Consolidated Balance Sheets.
GAS CONTRACTS: Our gas utility business uses fixed-priced weather-based gas supply call options and fixed-priced gas supply call and put options to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. Unrealized gains and losses associated with these options are reported directly in earnings as part of Other income, and then directly offset in earnings and recorded on the balance sheet as a regulatory asset or liability as part of the GCR process. At December 31, 2004, we held fixed-priced weather- based gas supply call options and had sold fixed-priced gas supply put options.
INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk associated with forecasted interest payments on variable-rate debt and to reduce the impact of interest rate fluctuations. Most of our interest rate swaps are designated as cash flow hedges. As such, we record changes in the fair value of these contracts in Accumulated other comprehensive loss unless the swaps are sold. For interest rate swaps that did not qualify for hedge accounting treatment, we record changes in the fair value of these contracts in earnings as part of Other income.
The following table reflects the outstanding floating-to-fixed interest rates swaps:
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, 2004 and December 31, 2003.
There was no ineffectiveness associated with any of the interest rate swaps that qualified for hedge accounting treatment. As of December 31, 2004, we have recorded an unrealized loss of $1 million, net of tax, in Accumulated other comprehensive loss related to interest rate risk contracts accounted for as cash flow hedges. We expect to reclassify this amount as a decrease to earnings during the next 12 months primarily to offset the variable-rate interest expense on hedged debt.
At December 31, 2004 and 2003, Shuweihat, Taweelah, and Jorf Lasfar, three of our equity method investees, held interest rate swaps that hedged the risk associated with variable-rate debt. These instruments are not included in this analysis, but can have an impact on financial results. The accounting for these instruments depends on whether they qualify for cash flow hedge accounting treatment. The interest rate swaps held by Taweelah do not qualify as cash flow hedges, and therefore, we record our proportionate share of the change in the fair value of these contracts in Earnings from Equity Method Investees. The remainder of these instruments do qualify as cash flow hedges, and we record our proportionate share of the change in the fair value of these contracts in Accumulated other comprehensive loss.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV PARTNERSHIP:
Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that certain of its long-term natural gas contracts qualify as normal purchases under SFAS No. 133 and therefore, these contracts were not recognized at fair value on the balance sheet as of December 31, 2004. The MCV Partnership also held certain long-term gas contracts that did not qualify as normal purchases as of December 31, 2004, because these contracts contained volume optionality. Accordingly, these contracts were accounted for as derivatives, with changes in fair value recorded in earnings each quarter. The MCV Partnership expects future earnings volatility on these contracts, since gains and
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losses will be recorded each quarter. For the year ended December 31, 2004, we recorded a $19 million net loss associated with these gas contracts in Fuel for electric generation on our Consolidated Statements of Income. The fair value of these contracts will reverse over the remaining life of the contracts ranging from 2005 to 2007.
Due to the implementation of the RCP in January 2005, the MCV Partnership has determined that a significant portion of its gas fuel contracts no longer qualify as normal purchases because the contracted gas will not be consumed for electric production. Accordingly, these contracts will be treated as derivatives and will be marked-to-market through earnings each quarter, which could increase earnings volatility. Based on market prices for natural gas as of January 31, 2005, the accounting for the MCV Partnership's long-term gas contracts, including those affected by the implementation of the RCP, could result in an estimated $100 million (pretax before minority interest) gain recorded to earnings in the first quarter of 2005. This estimated gain will reverse in subsequent quarters as the contracts settle. For further details on the RCP, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration Venture." If there are further changes in the level of planned electric production or gas consumption, the MCV Partnership may be required to account for additional long-term gas contracts as derivatives, which could add to earnings volatility.
Gas Fuel Futures and Swaps: The MCV Partnership enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements. At December 31, 2004, the MCV Partnership held gas fuel futures and swaps.
The contracts that are used to secure anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133. The MCV Partnership also engages in cost mitigation activities to offset the fixed charges the MCV Partnership incurs in operating the MCV Facility. These cost mitigation activities include the use of futures and options contracts to purchase and/or sell natural gas to maximize the use of the transportation and storage contracts when it is determined that they will not be needed for the MCV Facility operation. Although these cost mitigation activities do serve to offset the fixed monthly charges, these cost mitigation activities are not considered a normal course of business for the MCV Partnership and do not qualify as hedges. Therefore, the mark-to-market gains and losses from these cost mitigation activities are recorded in earnings each quarter.
As of December 31, 2004, we have recorded a cumulative net gain of $21 million, net of tax, in Accumulated other comprehensive loss relating to our proportionate share of the contracts held by the MCV Partnership that qualify as cash flow hedges. This balance represents natural gas futures, options, and swaps with maturities ranging from January 2005 to December 2009, of which $11 million of this gain is expected to be reclassified as an increase to earnings during the next 12 months. In addition, for the year ended December 31, 2004, we recorded a net gain of $37 million in earnings from hedging activities related to natural gas requirements for the MCV Facility operations and a net gain of $2 million in earnings from the MCV Partnership's cost mitigation activities.
CMS ERM CONTRACTS: Through December 31, 2002, our wholesale power and gas trading activities were accounted for under the mark-to-market method of accounting in accordance with EITF Issue No. 98-10. Effective January 1, 2003, EITF Issue No. 98-10 was rescinded and replaced by EITF Issue No. 02-03. As a result, only energy contracts that meet the definition of a derivative under SFAS No. 133 are to be carried at fair value. The impact of this change was recognized as a cumulative effect of a change in accounting principle loss of $23 million, net of tax, for the three month period ended March 31, 2003.
During 2003, we sold a majority of our wholesale natural gas and power-trading portfolio, and exited the energy services and retail customer choice business. As a result, our trading activities have been reduced
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significantly. Our current activities center around entering into energy contracts that are related to the activities considered to be an integral part of our ongoing operations. CMS ERM holds certain forward contracts for the purchase and sale of electricity and natural gas that result in physical delivery of the underlying commodity at contractual prices. These contracts are generally long-term in nature and are classified as non-trading. CMS ERM also uses various financial instruments, including swaps, options, and futures, to manage the commodity price risks associated with its forward purchase and sales contracts as well as generation assets owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading activities.
Non-trading and trading contracts that meet the definition of a derivative under SFAS No. 133 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 as a component of Operating Revenue in the period in which the changes occur. Gains and losses on trading contracts are recorded net in accordance with EITF Issue No. 02-03. Contracts that do not meet the definition of a derivative are accounted for as executory contracts (i.e., on an accrual basis).
FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option contracts to hedge certain receivables, payables, long-term debt, and equity value relating to our investments in foreign operations. 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 limit the risk from exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on assets and liabilities being hedged. At December 31, 2004 and 2003, we had no outstanding foreign exchange contracts.
The impact of hedges on our investments in foreign operations is reflected in Accumulated other comprehensive loss as a component of the foreign currency translation adjustment on our Consolidated Balance Sheets. Gains or losses from the settlement of these hedges are maintained in the foreign currency translation adjustment until we sell or liquidate the investments on which the hedges were taken. At December 31, 2004, the total foreign currency translation adjustment was a net loss of $319 million, which included a net hedging loss of $27 million, net of tax, related to settled contracts.
At December 31, 2004 and 2003, Taweelah, one of our equity method investees, held a foreign exchange contract that hedged the foreign currency risk associated with payments to be made under an operating and maintenance service agreement. This contract did not qualify as a cash flow hedge; and therefore, we record our proportionate share of the change in the fair value of the contract in Earnings from Equity Method Investees.
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,
- a defined contribution 401(k) plan,
- benefits to a select group of management under EISP, and
- health care and life insurance benefits under OPEB.
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 CMS-88
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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) in 2003 as a result of the increase in the additional minimum pension liability. As a result of Company contributions in 2003, 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. As a result, in 2003, we 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 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 $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 $67 million at December 31, 2004, and $66 million at December 31, 2003. The assets are classified as Other non-current assets. The Accumulated Benefit Obligation for SERP was $67 million at December 31, 2004 and $62 million at December 31, 2003.
401(k): Employer matching contributions to the 401(k) plan are invested in CMS Energy common stock. The amount charged to expense for this plan was $12 million in 2002. The employer's match for the 401(k) plan was suspended on September 1, 2002 and was resumed on January 1, 2005.
The MCV Partnership sponsors a defined contribution retirement plan covering all employees. Under the terms of the plan, the MCV Partnership makes contributions of either 5 or 10 percent of an employee's eligible annual compensation dependent upon the employee's age. The MCV Partnership also sponsors a 401(k) savings plan for employees. Contributions and costs for this plan are based on matching an employee's savings up to a maximum level. Amounts contributed under these plans were $1 million in 2004.
EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premium for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. EISP expense was less than $1 million in 2004, $1 million in 2003, and $2 million in 2002. The Accumulated Benefit Obligation for EISP was $4 million at December 31, 2004 and $3 million at December 31, 2003.
OPEB: Retiree health care costs at December 31, 2004 are based on the assumption that costs would increase 7.5 percent in 2004. The rate of increase is expected to be 10 percent for 2005. The rate of increase is expected to slow to an estimated 5 percent by 2010 and thereafter.
The MCV Partnership sponsors defined cost postretirement health care plans that cover all full-time employees, except key management. Participants in the postretirement health care plans become eligible for the benefits if they retire on or after the attainment of age 65 or upon a qualified disability retirement, or if they have 10 or more years of service and retire at age 55 or older. The accumulated benefit obligation of the MCV Partnership's postretirement plans was $5 million at December 31, 2004. The MCV Partnership's net periodic postretirement health care cost for 2004 was less than $1 million. CMS-89
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The health care cost trend rate assumption affects the estimated costs recorded. A one-percentage point change in the assumed health care cost trend assumption would have the following effects:
We adopted SFAS No. 106, effective as of the beginning of 1992. Consumers recorded a liability of $466 million for the accumulated transition obligation and a corresponding regulatory asset for anticipated recovery in utility rates. For additional details, see Note 1, Corporate Structure and Accounting Policies, "Utility Regulation." The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years.
The measurement date for all CMS Energy plans is November 30 for 2004, and December 31 for 2003 and 2002. We believe accelerating the measurement date on our benefits plans by one month is preferable as it improves control procedures and allows more time to review the completeness and accuracy of the actuarial measurements. As a result of the measurement date change in 2004, we recorded a $2 million cumulative effect of change in accounting, net of tax benefit, as a decrease to earnings. We also increased the amount of accrued benefit cost on our Consolidated Balance Sheets by $4 million. The effect of the measurement date change was immaterial. The measurement date for the MCV Partnership's plan is December 31, 2004.
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 expert opinions of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed periodically for reasonability and appropriateness.
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Costs: The following table recaps the costs incurred in our retirement benefits plans:
Reconciliations: The following table reconciles the funding of our retirement benefits plans with our retirement benefits plans' liability:
- ------------------------- (a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy, which is tax exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. CMS-91
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We believe our plan is actuarially equivalent to Medicare Part D and have incorporated, retroactively, the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $158 million. The remeasurement resulted in a reduction of OPEB cost of $24 million for 2004. The reduction of $24 million includes $7 million in capitalized OPEB costs. For additional details, see Note 16, Implementation of New Accounting Standards.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.082 billion exceeded the value of the Pension Plan assets and net balance sheet asset at December 31, 2004. As a result, we recorded an additional minimum liability of $419 million. Consistent with MPSC guidance, Consumers recognized the cost of their additional minimum liability as a regulatory asset. Accordingly, our additional minimum liability includes an intangible asset of $22 million, $17 million, net of tax of accumulated other comprehensive income, and a regulatory asset of $372 million. The Accumulated Benefit Obligation for the Pension Plan was $1.019 billion at December 31, 2003.
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
- ------------------------- (a) At November 30, 2004, there were 4,892,000 shares of CMS Energy Common Stock in the Pension Plan assets with a fair value of $50 million, and 493,000 shares in the OPEB plan assets with a fair value of $5 million. 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.
(b) The percentage of fixed income at December 31, 2003 is high because our December 2003 contribution of $350 million was deposited temporarily into fixed income securities.
We contributed $63 million to our OPEB plan in 2004. We plan to contribute $63 million to our OPEB plan in 2005. We did not contribute to our Pension Plan in 2004. We do not plan to contribute to our Pension Plan in 2005.
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 a Standard & Poor's 500 Index fund. The fixed income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each
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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.
Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:
- ------------------------- (a) OPEB benefit payments are net of employee contributions and expected Medicare Part D prescription drug subsidy payments.
8: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: This standard became effective January 2003. It requires companies to record the fair value of the cost to remove assets at the end of their useful life, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. For our regulated utility, as required by SFAS No. 71, we account for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would increase by $22 million.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock are based on decommissioning studies that largely utilize third-party cost estimates.
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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.
The Palisades and Big Rock cash flow revisions resulted from new decommissioning reports filed with the MPSC in March 2004. The Palisades ARO also reflects a cash flow revision for the probability of operating license renewal; the renewal would extend the plant's operating license by twenty years. For additional details, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Plant Decommissioning."
On October 14, 2004, the MPSC issued a generic proceeding to review SFAS No. 143, Accounting for Asset Retirement Obligations, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and their accounting and ratemaking issues. Utilities are required to respond to
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the Order by March 15, 2005. We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities; we anticipate no financial impact.
9: INCOME TAXES
CMS Energy and its subsidiaries file a consolidated federal income tax return. Income taxes generally are allocated based on each company's separate taxable income. We utilize deferred tax accounting for temporary differences.
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, 2004, we had AMT credit carryforwards in the amount of $218 million that do not expire and tax loss carryforwards in the amount of $1.348 billion that expire from 2021 through 2024. We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforward prior to its expiration. In addition, we had general business credit carryforwards in the amount of $41 million and charitable contribution carryforwards in the amount of $21 million that primarily expire in 2005, for which valuation allowances have been provided.
U.S. income taxes are not recorded on the undistributed earnings of foreign subsidiaries that have been or are intended to be reinvested indefinitely. Upon distribution, those earnings may be subject to both U.S. income taxes (adjusted for foreign tax credits or deductions) and withholding taxes payable to various foreign countries. We determine annually 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 $211 million at December 31, 2004. It is impractical to estimate the amount of unrecognized deferred income taxes or withholding taxes on these undistributed earnings. Also, at December 31, 2004 and 2003, 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 American Jobs Creation Act of 2004 creates a one-year opportunity to receive a tax benefit for U.S. corporations that reinvest dividends from controlled foreign corporations in the U.S. in a 12-month period (calendar year 2005 for CMS Energy). Although the tax benefit is subject to a number of limitations, we believe that we have the information necessary to make an informed decision on the impact of this act on our repatriation plan.
In January 2005, we repatriated $80 million in cash, $71 million of which should qualify for the tax benefit. Historically, we recorded deferred taxes on these repatriated earnings. Since this repatriation should qualify for the tax benefit and our decision to repatriate was made in 2004, we have reversed $21 million of our deferred tax liability. This adjustment was recorded as a component of income from continuing operations in 2004.
During 2005, we may have the ability to repatriate additional amounts that may qualify for the repatriation tax benefit. If successful, our current estimate is that additional amounts could range between $100 million and $120 million. The amount of additional repatriation remains uncertain because it is based on future foreign subsidiary operations, cash flow, financings, and repatriation limitations. This potential additional repatriation could reduce our recorded deferred tax liability $30 million to $36 million. We expect to be in a position to finalize our assessment, which may be higher or lower, regarding any potential repatriation in the fourth quarter of 2005.
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The significant components of income tax expense (benefit) on continuing operations consisted of:
Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.
The principal components of deferred tax assets (liabilities) recognized in our Consolidated Balance Sheets 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 from 2002 to 2003 is primarily attributable to the valuation reserve provisions for the possible lost general business credit, capital loss, and charitable contribution carryforwards. The decreased income tax expense from 2003 to 2004 is primarily attributable to the benefit recorded from the American Jobs Creation Act of 2004 of $21 million.
(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.
The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which can result in proposed assessments. The IRS is currently conducting audits of our federal income tax returns for the years 1998 through 2002. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities are adequate for all years.
10: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee Directors or consultants based on their contributions to the successful management of the company. On May 28, 2004, shareholders approved an amendment to the Plan, with an effective date of June 1, 2004. The amendment established a 5-year term for the Plan. The Plan includes the following type of awards:
- phantom shares,
- performance units,
- restricted stock,
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- stock options,
- stock appreciation rights, and
- management stock purchases.
Phantom shares are valued at the fair market price of common stock when granted. They give the holder the right to receive the appreciation value of common stock on one or more valuation dates, according to a specified vesting schedule determined at time of grant. These shares are subject to forfeiture if employment terminates before vesting.
Performance units have an initial value that is established at time of grant. Performance criteria are established at the time of grant and, depending upon the extent to which they are met, will determine the value of the payout, which may be in the form of cash, common stock, or a combination of both. These units are subject to forfeiture if employment terminates.
Restricted shares of common stock are outstanding shares with full voting and dividend rights. These awards vest 100 percent after three years and are subject to achievement of specified levels of total shareholder return including a comparison to a peer group of companies. Some awards vest based solely on continued employment. These awards 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, defined as the excess of the market price of the stock at the date of exercise over the grant date price. All stock options and stock appreciation rights are valued at fair market price when granted. All options and rights may be exercised upon grant, and expire up to 10 years and one month from the date of grant.
Management stock purchases are the election of select participants in the Officer's Incentive Compensation Plan to receive all or a portion of their incentive payments in the form of shares of restricted common stock or shares of restricted stock units. These participants may also receive awards of additional restricted common stock or restricted stock units provided that the total value of these additional grants does not exceed $2.5 million for any fiscal year.
Under the revised Plan, shares awarded or subject to options, phantom shares and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such grants or awards to any participant exceed 250,000 shares in any fiscal year.
Shares for which payment or exercise is in cash, as well as shares or options that are forfeited, may be awarded or granted again under the Plan.
Awards of up to 5,482,690 shares of CMS Energy Common Stock may be issued as of December 31, 2004. All grants awarded under this Plan in 2004 were in the form of restricted stock.
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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, 2004, 426,500 of the 1,377,010 shares of restricted common stock outstanding are subject to performance objectives. Compensation expense included in income for restricted stock was $2 million for 2004, $2 million in 2003, and less than $1 million in 2002.
The following table summarizes our stock options outstanding at December 31, 2004:
The number of stock options exercisable was 4,778,488 at December 31, 2004, 5,795,145 at December 31, 2003 and 5,007,329 at December 31, 2002.
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) There were no stock option grants during 2004.
(b) For 2002, there were two stock option grants totaling 1,492,200 options.
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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) There were no stock option grants during 2004.
(b) For 2002, there were two stock option grants totaling 1,492,200 options.
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.
11: 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 fair value, or
- renew the lease at fair rental value.
Our capital leases are comprised mainly of leased service vehicles and office furniture. As of December 31, 2004, capital lease obligations totaled $58 million. Consumers is authorized by the MPSC to record both capital and operating lease payments as operating expenses and recover the total costs from their customers. Capital lease expenses were $13 million in 2004, $17 million in 2003, and $20 million in 2002. In November 2003, we exercised our purchase option under the capital lease agreement for our main headquarters building in Jackson, Michigan. Operating lease charges were $14 million in 2004, $14 million in 2003, and $13 million in 2002. Income from subleases was $1 million in 2004 and $1 million in 2003.
In order to obtain permanent financing for the MCV Facility, the MCV Partnership entered into a sale and lease back agreement with a lessor group, which includes the FMLP, for substantially all of the MCV Partnership's fixed assets. In accordance with SFAS No. 98, the MCV Partnership accounted for the transaction as a financing arrangement. As of December 31, 2004, finance lease obligations totaled $286 million, which represents the third-party portion of the MCV Partnership's finance lease obligation.
Charges under the MCV Partnership's finance lease obligation were $105 million in 2004. For additional details on transactions with the MCV Partnership and the FMLP, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration Venture."
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Minimum annual rental commitments under our non-cancelable leases at December 31, 2004 were:
- ------------------------- (a) Minimum payments have not been reduced by minimum sublease rentals of $2 million due in the future under noncancelable subleases.
12: EQUITY METHOD INVESTMENTS
Where ownership is more than 20 percent but less than a majority, we account for certain investments in other companies, partnerships, and joint ventures by the equity method of accounting in accordance with APB Opinion No. 18. Net income from these investments included undistributed earnings of $88 million in 2004, $41 million in 2003, and $39 million in 2002.
The most significant of these investments are:
- our 50 percent interest in Jorf Lasfar, and
- our 40 percent interest in Taweelah.
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Summarized financial information for these equity method investments is as follows:
Income Statement Data
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Balance Sheet Data
- ------------------------- (a) Our investment in Jorf Lasfar was $309 million at December 31, 2004 and $256 million at December 31, 2003. Our share of net income from Jorf Lasfar was $63 million for the year ended December 31, 2004, $60 million for the year ended December 31, 2003, and $66 million for the year ended December 31, 2002.
(b) Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the FMLP and have consolidated their assets, liabilities, and financial activities for 2004.
(c) In August 2004, we sold our investment in SCP.
(d) For 2003 and 2002, the MCV Partnership was accounted for as an equity method investment but their summarized financial information is not included in these tables. Our 49 percent investment in the MCV Partnership was $419 million at December 31, 2003 and our share of net income was $29 million for the year ended December 31, 2003 and $65 million for the year ended December 31, 2002. Such information is shown below in the section "Summarized Financial Information of Significant Related Energy Supplier." Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the MCV Partnership. We consolidated their assets, liabilities, and financial activities into our financial statements as of and for the
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year ended December 31, 2004. As of December 31, 2004, the MCV Partnership had total assets of $1.980 billion and a net loss of $24 million for the year.
SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER: Under the PPA with the MCV Partnership discussed in Note 3, Contingencies, 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 for 2003 and 2002 follows:
Statements of Income
Balance Sheet
- ------------------------- (a) Revenue from Consumers totaled $514 million in 2003 and $557 million in 2002.
(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) in 2002.
(c) Receivables from Consumers totaled $40 million for December 31, 2003.
(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 the 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.
13: GOODWILL
The changes in the carrying amount of goodwill for the years ended December 31, 2003 and 2004, by reportable segment, are as follows:
- ------------------------- (a) In 2003, we performed an impairment test on the Enterprises segment which determined the book value of our goodwill related to CPEE exceeded the fair value. Therefore, we recorded a goodwill impairment.
(b) In the fourth quarter of 2004, an impairment charge was recorded to recognize a reduction in fair value as a result of the sale of GVK, which included a goodwill impairment of $5 million. We closed on the sale of GVK in February 2005.
14: 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 CMS-105
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ownership interest. The following table indicates the extent of our investment in jointly owned regulated utility facilities:
15: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by their products and services. We evaluate performance based upon the net income of each segment. We operate principally in three reportable segments: electric utility, gas utility, and enterprises.
The electric utility segment consists of regulated activities associated with the generation and distribution of electricity in the state of Michigan through our subsidiary, Consumers. The gas utility segment consists of regulated activities associated with the transportation, storage, and distribution of natural gas in the state of Michigan through our subsidiary, Consumers. The enterprises segment consists of:
- investing in, acquiring, developing, constructing, managing, and operating non-utility power generation plants and natural gas facilities in the United States and abroad, and
- providing gas, oil, and electric marketing services to energy users.
Accounting policies of our segments are the same as we describe in the summary of significant accounting policies. Our financial statements reflect the assets, liabilities, revenues, and expenses directly related to the individual segments where it is appropriate. We allocate accounts between the segments where common accounts are attributable to more than one segment. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, other operation and maintenance expense, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue. Pension provisions are allocated based on labor dollars. We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income (loss) by segment.
The "Other" segment includes corporate interest and other, discontinued operations, and the cumulative effect of accounting changes. The following tables show our financial information by reportable segment:
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, purchase of nuclear fuel, and other assets. 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.
16: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The FASB issued this Interpretation in January 2003. The objective of the Interpretation is to assist in determining when one party controls another entity in circumstances where a controlling financial interest cannot be properly identified based on voting interests. Entities with this characteristic are considered variable interest entities. The Interpretation requires the party with the controlling financial interest, known as the primary beneficiary, in a variable interest entity to consolidate the entity.
In December 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that had not previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No. 46 provided an implementation deferral until the first quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV Partnership and the FMLP. We have a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the MCV Facility, which results in Consumers holding a 35 percent lessor interest in the MCV Facility. Collectively, these interests make us the primary beneficiary of these entities. As such, we consolidated their assets, liabilities, and activities into our financial statements as of and for the year ended December 31, 2004. These partnerships have third-party obligations totaling $582 million at December 31, 2004. Property, plant, and equipment serving as collateral for these
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
obligations has a carrying value of $1.426 billion at December 31, 2004. The creditors of these partnerships do not have recourse to the general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of three other entities that are determined to be variable interest entities. We have 50 percent partnership interest in the T.E.S. Filer City Station Limited Partnership, the Grayling Generating Station Limited Partnership, and the Genesee Power Station Limited Partnership. Additionally, we have operating and management contracts and are the primary purchaser of power from each partnership through long-term power purchase agreements. Collectively, these interests make us the primary beneficiary as defined by the Interpretation. Therefore, we consolidated these partnerships into our consolidated financial statements beginning in 2003. These partnerships have third-party obligations totaling $116 million at December 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $168 million as of December 31, 2004. Other than outstanding letters of credit and guarantees of $5 million, the creditors of these partnerships do not have recourse to the general credit of CMS Energy.
We determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities were deconsolidated as of December 31, 2003. Company Obligated Trust Preferred Securities totaling $663 million that were previously included in mezzanine equity, were eliminated due to deconsolidation. At December 31, 2004, we reflected Long-term debt -- related parties of $504 million, current portion of Long-term debt -- related parties of $180 million, and an investment in related parties of $21 million.
We are not required to restate prior periods for the impact of this accounting change.
Additionally, we have variable interest entities in which we are not the primary beneficiary. FASB Interpretation No. 46 requires us to disclose certain information about these entities. The following chart details our involvement in these entities at December 31, 2004:
- ------------------------- (a) At December 31, 2004, the balance includes our proportionate share of the negative fair value of derivative instruments of $25 million.
Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $122 million, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $84 million. In the third quarter of 2004, we contributed an investment of $70 million in Shuweihat. The contribution was made pursuant to the Shuweihat Shareholders' Agreement, which was entered into in 2001.
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $158 million. The remeasurement resulted in a total OPEB cost reduction of $24 million for 2004. Consumers capitalizes a portion of OPEB cost in accordance with regulatory accounting. As such, the remeasurement resulted in a net reduction of OPEB expense of $17 million for 2004.
EITF ISSUE NO. 04-8, THE EFFECT OF CONTINGENTLY CONVERTIBLE DEBT ON DILUTED EARNINGS PER SHARE: At its September 2004 meeting, the EITF reached a final consensus that contingently convertible instruments should be included in the diluted earnings per share computation (if dilutive) regardless of whether the market price trigger has been met.
In December 2004, we completed an exchange offer for our 3.375 percent contingently convertible senior notes and our 4.50 percent contingently convertible preferred stock. For additional information, see Note 4, Financings and Capitalization, "Contingently Convertible Securities."
We adopted the provisions of EITF Issue No. 04-8 as of December 31, 2004. Upon adoption, our 2004 year-to-date diluted earnings per share was reduced by $0.01 per share. Adoption of this EITF Issue did not impact our diluted earnings per share for any prior periods.
FSP 109-1, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE TAX DEDUCTION PROVIDED TO U.S. BASED MANUFACTURERS BY THE AMERICAN JOBS CREATION ACT OF 2004: The American Jobs Creation Act of 2004 provides for a deduction, starting in 2005, of a portion of the income from certain production activities, including the production of electricity. FSP 109-1 indicates that the deduction should be accounted for as a special deduction rather than a tax rate reduction under SFAS No. 109. We are currently studying this act for its impact on us; however, we do not anticipate a material amount of tax benefit from the domestic production activities deduction in the near future.
FSP 109-2, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE FOREIGN EARNINGS REPATRIATION PROVISION WITHIN THE AMERICAN JOBS CREATION ACT OF 2004: The American Jobs Creation Act of 2004 creates a one-year opportunity to receive a tax benefit for U.S. corporations that reinvest dividends from controlled foreign corporations in the U.S. in a 12-month period (2005 for CMS Energy). Although the tax benefit is subject to a number of limitations, we believe that we have the information necessary to make an informed decision on the impact of this act on our repatriation plan. FSP 109-2 provides accounting guidance and disclosure requirements relating to this act. For additional details, see Note 9, Income Taxes.
EITF ISSUE NO. 03-1, THE MEANING OF OTHER-THAN-TEMPORARY IMPAIRMENTS: The Issue addresses the definition of an other-than-temporary impairment of certain investments and provides additional disclosure requirements. The scope of EITF Issue No. 03-1 includes debt and equity securities accounted for under SFAS No. 115, debt and equity securities held by non-profit organizations under SFAS No. 124, and cost method investments under APB No. 18. We analyzed our in-scope investments under the guidance of this Issue and have provided additional disclosures.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to expense the grant date fair value of employee stock options and similar awards. The Statement also clarifies and expands SFAS No. 123's guidance in several areas, including measuring fair value, classifying an award as equity or as a liability, and attributing compensation cost to reporting periods.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to require that excess tax benefits related to the excess of the tax deductible amount over the compensation cost recognized be classified as a financing cash inflow rather than as a reduction of taxes paid in operating cash flows.
This Statement is effective for us as of the beginning of the third quarter of 2005. We adopted the fair value method of accounting for share-based awards effective December 2002, and therefore, expect this Statement to have an insignificant impact on our results of operations when it becomes effective.
17: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- ------------------------- (a) As of March 31, 2004, we determined that the MCV Partnership and the FMLP should be consolidated in accordance with revised FASB Interpretation No. 46. As such, we consolidated their financial activities into our financial statements as of and for the year ended December 31, 2004. For additional details, see Note 16, Implementation of New Accounting Standards.
(b) Net of tax.
(c) Quarterly data for March 31, 2004 differs from amounts previously reported as a result of accelerating the measurement date on our benefit plans by one month. For additional information, see Note 7, Retirement Benefits.
(d) Quarterly data for March 31, 2004 differs from amounts previously reported due to the remeasurement of our post retirement benefit obligation in accordance with FASB Staff Position, No. SFAS 106-2. For additional information, see Note 16, Implementation of New Accounting Standards.
(e) Sum of the quarters may not equal the annual earnings per share due to changes in shares outstanding.
(f) Based on New York Stock Exchange -- Composite transactions.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of CMS Energy Corporation
We have audited the accompanying consolidated balance sheets of CMS Energy Corporation (a Michigan corporation) as of December 31, 2004 and 2003, 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, 2004. 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 49% owned variable interest entity which has been consolidated in 2004 pursuant to Revised Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities" and accounted for under the equity method of accounting in 2003 and 2002 and Jorf Lasfar Energy Company S.C.A., which represents an investment accounted for under the equity method of accounting, have been audited by other auditors 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of CMS Energy Corporation at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 16 to the consolidated financial statements, in 2004, the Company adopted Revised Financial Accounting Standards Board (FASB) Interpretation No. 46, "Consolidation of Variable Interest Entities". In addition, as discussed in Note 7 to the consolidated financial statements, in 2004, the Company changed its measurement date for all CMS Energy Corporation pension and postretirement benefit plans. As discussed in Notes 6, 8, and 16 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 FASB Interpretation No. 46, "Consolidation of Variable Interest Entities".
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of CMS Energy Corporation's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2005 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Detroit, Michigan March 7, 2005
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of Midland Cogeneration Venture Limited Partnership:
We have completed an integrated audit of Midland Cogeneration Venture Limited Partnership's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
CONSOLIDATED FINANCIAL STATEMENTS
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows (not presented herein) present fairly, in all material respects, the financial position of Midland Cogeneration Limited Partnership (a Michigan limited partnership) and its subsidiaries (MCV) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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.
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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting, that MCV maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, MCV maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by COSO. MCV's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of MCV's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
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accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan February 25, 2005
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REPORT OF INDEPENDENT AUDITORS
To the Management Committee and Stockholders of Jorf Lasfar Energy Company S.C.A. B.P. 99 Sidi Bouzid El Jadida
We have audited the accompanying balance sheets of Jorf Lasfar Energy Company S.C.A. (the "Company") as of December 31, 2004, 2003 and 2002, and the related statements of income, of stockholders' equity and of cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Jorf Lasfar Energy Company S.C.A. at December 31, 2004, 2003 and 2002, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Price Waterhouse
Price Waterhouse Casablanca, Morocco, February 11, 2005
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[CONSUMERS ENERGY LOGO]
2004 CONSOLIDATED 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) Under revised FASB Interpretation No. 46, we are the primary beneficiary of the MCV Partnership and the FMLP. As a result, we have consolidated their assets, liabilities and activities into our financial statements as of and for the year ended December 31, 2004. These partnerships had third party obligations totaling $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $1.426 billion at December 31, 2004.
(c) Effective December 31, 2003, Trust Preferred Securities are classified on the balance sheets as Long-term debt -- related parties.
(d) Effective November 2002, Michigan Gas Storage Company was merged into Consumers.
(e) Excludes off-system transportation customers.
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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 of services each provides. We operate principally in two business segments: electric utility and gas utility. Our electric utility operations include the generation, purchase, distribution, and sale of electricity. Our gas utility operations include the purchase, transportation, storage, distribution, and sale of natural gas.
We earn our revenue and generate cash from operations by providing electric and natural gas utility services, electric power generation, gas transmission and storage, and other energy related services. Our businesses are affected primarily 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 business strategy involves improving our balance sheet and maintaining focus on our core strength: superior utility operation and service. Over the next few years, we expect that this strategy will result in improved credit ratings, earnings growth, and a company positioned to make new investments.
Despite strong financial and operational performance, we face important challenges in the future. We continue to lose industrial and commercial customers to alternative electric suppliers as a result of Michigan's Customer Choice Act. As of March 2005, we have lost 900 MW, or 12 percent, of our electric load to these alternative electric suppliers. Based on current trends, we predict total load loss by the end of 2005 to be in the range of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load loss will fall within that range. Existing state legislation encourages competition and provides for recovery of Stranded Costs caused by the lost sales. In fact, in November 2004, the MPSC ordered us to recover 2002 and 2003 Stranded Costs in the amount of $63 million. In 2004, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act.
Another important challenge relates to the economics of the MCV Partnership. The MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. In January 2005, the MPSC issued an order approving the RCP to change the way the facility is used. The purpose of the RCP is to conserve natural gas through a change in the dispatch of the MCV Facility and thereby improve the financial performance of the MCV Partnership without increased costs to customers. The approved plan will:
- allow for dispatching the MCV Facility based on natural gas market prices, which is expected to reduce gas consumption by an estimated 30 to 40 bcf per year,
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- allocate 50 percent of our direct savings to customers in 2005 and 70 percent of our direct savings to customers thereafter, and
- fund $5 million annually for renewable energy sources such as wind power projects.
We are focused on further reducing our business, financial, and regulatory risks, while growing the equity base of our company. In 2004, we issued over $1 billion in FMBs. Proceeds from these transactions were used to retire other higher-interest rate long-term debt. Also in 2004, we received cash contributions from CMS Energy of $250 million, providing additional liquidity and flexibility for our operations. In January 2005, we continued to retire higher-interest rate debt through the use of proceeds from the issuance of $250 million of FMBs. We also received an additional cash contribution from CMS Energy of $200 million in January 2005. The efforts, and others, are designed to lead us to be a strong, reliable utility company that will be poised to take advantage of opportunities for further growth.
CONSOLIDATION OF THE MCV PARTNERSHIP AND THE FMLP
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the MCV Partnership and the FMLP. As a result, we have consolidated the assets, liabilities, and activities of these entities into our financial statements as of and for the year ended December 31, 2004. These entities are reported as equity method investments in our financial statements for all periods prior to January 1, 2004. For additional details, see Note 13, Implementation of New Accounting Standards.
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 by the Private Securities Litigation Reform Act of 1995. Our intention with the use of words such as "may," "could," "anticipates," "believes," "estimates," "expects," "intends," "plans," and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict and/or control:
- capital and financial market conditions, including the price of CMS Energy Common Stock and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets as well as availability of financing to Consumers, CMS Energy, or any of their affiliates and the energy industry,
- market perception of the energy industry, Consumers, CMS Energy, or any of their affiliates,
- credit ratings of Consumers, CMS Energy, or any of their affiliates,
- factors affecting utility and diversified energy operations such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints,
- international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions,
- potentially adverse regulatory treatment and/or regulatory lag concerning a number of significant questions presently before the MPSC relating to the Customer Choice Act including:
- recovery of future Stranded Costs incurred due to customers choosing alternative energy suppliers,
- recovery of Clean Air Act costs and other environmental and safety-related expenditures,
- power supply and natural gas supply costs when oil prices and other fuel prices are rapidly increasing, CE-4
- timely recognition in rates of additional equity investments in Consumers, and
- adequate and timely recovery of additional electric and gas rate-based expenditures,
- the impact of adverse natural gas prices on the MCV Partnership investment, and regulatory decisions that limit our recovery of capacity and fixed energy payments,
- federal regulation of electric sales and transmission of electricity including periodic re-examination by federal regulators of our market-based sales authorizations in wholesale power markets without price restrictions,
- energy markets, including the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity, and certain related products due to lower or higher demand, shortages, transportation problems, or other developments,
- potential for the Midwest Energy Market to develop into an active energy market in the state of Michigan, which may lead us to account for electric capacity and energy contracts with the MCV Partnership and other independent power producers as derivatives,
- the GAAP requirement that we utilize mark-to-market accounting on certain of our energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods and could add to earnings volatility,
- potential disruption or interruption of facilities or operations due to accidents or terrorism, and the ability to obtain or maintain insurance coverage for such events,
- nuclear power plant performance, decommissioning, policies, procedures, incidents, and regulation, including the availability of spent nuclear fuel storage,
- technological developments in energy production, delivery, and usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or policies,
- outcome, cost, and other effects of legal and administrative proceedings, settlements, investigations and claims,
- limitations on our ability to control the development or operation of projects in which our subsidiaries have a minority interest,
- disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance and performance bonds,
- other business or investment considerations that may be disclosed from time to time in Consumers' or CMS Energy's SEC filings, or in other publicly issued written documents, and
- other uncertainties that are difficult to predict, and many of which are beyond our control.
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RESULTS OF OPERATIONS
NET INCOME AVAILABLE TO COMMON STOCKHOLDER
For the year 2004, our net income available to the common stockholder was $277 million, compared to net income available to the common stockholder of $194 million for the year 2003. The $83 million increase in net income available to the common stockholder reflects:
- an $82 million decrease in operating expense, reflecting the MPSC's approval for recovery of stranded costs for 2002 and 2003, the deferral of electric depreciation expense on our excess capital expenditures as permitted by the Customer Choice Act, reduced gas depreciation rates as authorized by the MPSC, decreased pension costs, and the 2004 reduction to benefit expense due to the subsidy provided under Part D of the Medicare Prescription Drug, Improvement and Modernization Act,
- a $73 million increase in other income, reflecting the return on certain costs recoverable under the Customer Choice Act beginning in 2004,
- an $18 million increase in gas utility revenues due to the MPSC's December 2003 interim and October 2004 final gas rate orders,
- the absence of a $12 million charge taken in 2003 to reflect a decline in the market value of CMS Energy common stock held by us,
- a $5 million increase in gas wholesale and retail services and other gas revenues, primarily due to the absence of a 2003 revenue reduction due to the 2002-2003 GCR disallowance.
These increases to net income available to the common stockholder were offset partially by reductions to net income available to the common stockholder from:
- a $33 million increase in fixed charges because we expensed capitalized interest on the Clean Air Act costs incurred during the period of June 2000 through December 2003 and increased our average borrowings,
- a $22 million decrease in electric delivery revenue primarily due to tariff revenue reductions, customers choosing alternative electric suppliers, and milder summer temperatures' negative impact on air conditioning usage,
- a $19 million decrease in earnings from our ownership interest in the MCV Partnership primarily due to increases in non-recoverable fuel costs incurred at the MCV Facility,
- a $20 million underrecovery of power supply revenue due to non-recoverable power supply costs related to capped customers,
- an $8 million increase in general taxes primarily due to the absence of a 2003 reduction to MSBT expense from a tax credit received for construction of our corporate headquarters on a Brownfield site, and
- a $5 million reduction in gas delivery revenue due to milder weather.
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For the year 2003, our net income available to the common stockholder was $194 million, compared to net income available to the common stockholder of $335 million for the year 2002. The $141 million decrease in net income available to the common stockholder primarily reflects:
- an $80 million increase in operating expense due to higher pension and other benefit costs, and increased depreciation and amortization expense,
- a $27 million decrease in electric delivery revenue due to milder summer weather and the migration of commercial and industrial customers to alternative electric suppliers,
- a $27 million decline in earnings from our ownership interest in the MCV Partnership primarily due to the decrease in fair value of certain gas contracts held by the MCV Partnership,
- a $23 million increase in fixed charges due to higher average debt levels and higher average interest rates,
- a $7 million charge at CMS Holdings to reflect the loss of certain tax credits, and
- the absence of a $31 million gain primarily associated with the sale of our electric transmission system in 2002.
These decreases to net income were offset partially by increases to net income from:
- a $25 million increase in gas tariff rates authorized by the MPSC in late 2002,
- an $8 million decrease of general tax expense primarily due to reduced MSBT expense from a tax credit received for building our corporate headquarters on a Brownfield site, and
- a $17 million benefit from power supply overrecoveries due to lower average fuel costs and higher market prices for excess capacity sold.
For additional details, see "Electric Utility Results of Operations" and "Gas Utility Results of Operations" within this section and Note 2, Contingencies.
ELECTRIC UTILITY RESULTS OF OPERATIONS
ELECTRIC DELIVERIES: For the year 2004, electric deliveries including transactions with other wholesale marketers, other electric utilities, and customers choosing alternative electric suppliers increased 1.3 billion kWh or 3.3 percent versus 2003. Despite the increase in electric deliveries, electric delivery revenue decreased due to the milder summer temperatures' negative impact on higher margin residential customer air conditioning usage, customers choosing alternative electric suppliers, and tariff revenue reductions. The tariff revenue reductions
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began on January 1, 2004, and were equivalent to the Big Rock nuclear decommissioning surcharge in effect when our electric retail rates were frozen from June 2000 through December 31, 2003. The tariff revenue reductions decreased electric delivery revenue by $35 million.
Surcharges related to the recovery of costs incurred in the transition to customer choice offset partially the reductions to electric delivery revenue. Recovery of these costs began on July 1, 2004 and increased electric delivery revenue by $10 million.
For the year 2003, electric delivery revenue decreased, reflecting lower deliveries versus 2002. Most significantly, sales volumes to commercial and industrial customers were lower than in 2002, a result of these sectors' continued migration to alternative electric suppliers as allowed by the Customer Choice Act. Milder summer temperatures reduced air conditioning usage by the higher-margin residential customers, further decreasing electric delivery revenue. Overall, electric deliveries, including transactions with other wholesale marketers and other electric utilities, decreased 0.4 billion kWh or 1.1 percent.
POWER SUPPLY COSTS AND RELATED REVENUE: For the year 2004, our recovery of power supply costs was capped for the residential and small commercial customer classes. Operating income decreased $31 million in 2004 versus 2003 primarily due to power supply-related costs exceeding power supply-related revenue charged to capped customers. Power supply-related costs increased in 2004 primarily due to higher priced purchased power necessary to replace the generation loss from an extended refueling outage at our Palisades nuclear generating plant and higher coal prices.
For the year 2003, our recovery of power supply costs was fixed for all customers, as required under the Customer Choice Act. Therefore, power supply-related revenue in excess of actual power supply costs increased operating income. By contrast, if power supply-related revenue had been less than actual power supply costs, the impact would have decreased operating income. For the year 2003, power supply-related revenue in excess of actual power supply costs benefited operating income by $26 million versus 2002. This increase was primarily the result of increased intersystem revenue, efficient operation of our generating plants, and lower priced purchased power.
OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: For the year 2004, other income increased $7 million, other operating expenses decreased $82 million, and non-commodity revenue decreased $3 million versus 2003. Other income increased primarily due to $7 million of interest income related to our 2002 and 2003 Stranded Cost recovery as authorized by the MPSC. Our recognition of this recovery decreased operating expense $57 million in 2004, and along with decreased depreciation, pension, and benefit costs contributed to the reduction in other operating expenses. The decrease in depreciation expense reflects our ability to defer depreciation expense on the excess of capital expenditures over our depreciation base as authorized by the Customer Choice Act. The decrease in pension expense reflects fewer current year retirees choosing to receive a single lump sum distribution, and increased plan earnings from higher average plan assets. The reduction in benefit expense is due to the subsidy provided under Part D of the Medicare Prescription Drug, Improvement and Modernization Act.
For the year 2003, net other operating expenses, other income and non-commodity revenue decreased operating income versus 2002. The decrease related to increased pension and other benefit costs, a scheduled refueling outage at Palisades, and higher transmission costs. In addition, depreciation and amortization expense increased, reflecting higher levels of plant in service, and higher amortization of securitized assets. Higher non-commodity revenue associated with other income offset slightly the increased operating expenses.
REGULATORY RETURN ON CAPITAL EXPENDITURES: As allowed by Section 10d(4) of the Customer Choice Act, on January 1, 2004, we began recording the 2004 portion of the return on certain capital expenditures incurred during the rate freeze period of June 2000 through December 2003. This increased income by $41 million in 2004. Based on an interpretation of the Customer Choice Act by the MPSC in a rate order involving Detroit Edison, in November 2004 we recorded an additional $72 million return on Clean Air Act costs incurred during the period of June 2000 through December 2003.
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GAIN ON ASSET SALES: The reduction in operating income from asset sales for 2003 versus 2002 reflected 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: For the year 2004, general taxes increased primarily due to increases in property tax expense and the absence of a MSBT credit received in 2003. The 2003 MSBT credit was associated with the construction of our corporate headquarters on a qualifying Brownfield site. For the year 2003, this MSBT credit decreased general taxes versus 2002.
FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest. Additionally, to recognize a recently issued interpretation of the Customer Choice Act by the MPSC, we expensed $31 million of capitalized interest in November related to Clean Air Act costs incurred during the period of June 2000 through December 2003.
For the year 2003, fixed charges increased versus 2002 due to higher average debt levels and higher average interest rates.
INCOME TAXES: For the year 2004, income taxes increased due to increased earnings from the electric utility versus 2003. The increase in income taxes from the tax treatment of items related to plant, property and equipment as required by past MPSC orders was offset by Part D of the Medicare Prescription Drug, Improvement and Modernization Act which provides a subsidy that is exempt from federal taxation. For the year 2003, income tax expense decreased versus 2002 primarily due to lower earnings by the electric utility.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF TAX EXPENSE: The measurement date for all of Consumers' plans is November 30 for 2004, and December 31 for 2003 and 2002. We believe accelerating the measurement date on our benefit plans by one month is preferable as it improves control procedures and allows more time to review the completeness and accuracy of the actuarial measurements. As a result of the measurement date change, we recorded a $1 million, net of tax, cumulative effect adjustment as a decrease to earnings. For additional details, see Note 5, Retirement Benefits.
GAS UTILITY RESULTS OF OPERATIONS
GAS DELIVERIES: For the year 2004, gas deliveries, including transportation to end-use customers, decreased 15.5 bcf or 4.6 percent due to milder weather versus 2003. Most significantly, temperatures in the first quarter of the year were 12.1 percent warmer than in the same period in 2003.
For the year 2003, gas deliveries, including miscellaneous transportation, increased due to colder weather during the first quarter of 2003 versus 2002. Increased deliveries to the residential and commercial sectors resulted in a $6 million increase in gas revenue. This revenue increase was offset by a $7 million reduction to gas revenue associated with our analysis of gas losses related to the gas transmission and distribution system.
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GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order authorizing a $19 million annual increase to gas tariff rates. In October 2004, the MPSC issued a final order authorizing an increase of $58 million in each of the next two years. As a result of these orders, gas revenues increased $28 million for the year 2004 versus 2003.
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, gas revenue increased $39 million for the year 2003 versus 2002.
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUE AND OTHER INCOME: In 2004, gas wholesale and retail services and other gas revenue increased primarily due to the absence of certain 2003 reductions to revenue. In 2003, gas revenue was reduced primarily due to an $11 million 2002-2003 GCR disallowance.
For the year 2003, gas wholesale and retail services and other gas revenue increased versus 2002. This increase was primarily due to increased gas title tracking services and miscellaneous revenue in 2003. The increased revenue was offset partially by a disallowance for the 2002-2003 GCR year.
OPERATION AND MAINTENANCE: For the year 2004 versus 2003, operation and maintenance expenses decreased versus 2003 primarily due to reduced pension and benefit expense of $23 million. The decrease in pension expense reflects fewer current year retirees choosing to receive a single lump sum distribution, and increased plan earnings from higher average plan assets. The reduction in benefit expense is due to the subsidy provided under Part D of the Medicare Prescription Drug, Improvement and Modernization Act. These reductions were offset partially by additional expenditures on safety, reliability, and customer service.
For the year 2003, operation and maintenance expenses increased versus 2002 due to increases in pension and other benefit costs of $27 million and additional expenditures on safety, reliability, and customer service.
GENERAL TAXES: For the year 2004, general taxes increased due to the absence of a MSBT credit received in 2003. The 2003 MSBT credit received from the State of Michigan was associated with the construction of our corporate headquarters on a qualifying Brownfield site. For the year 2003, this MSBT credit decreased general taxes versus 2002.
DEPRECIATION: For the year 2004 versus 2003, depreciation expense decreased primarily due to reduced rates authorized by the MPSC's December 2003 interim rate order and the MPSC's October 2004 order, as modified by its December 2004 order granting rehearing. For the year 2003, depreciation expense increased because of increased plant in service versus 2002.
FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest. For the year 2003, fixed charges increased versus 2002 due to higher average debt levels and higher average interest rates.
INCOME TAXES: For the year 2004, income taxes increased due to increased earnings from the gas utility versus 2003. The increase in income taxes was offset partially by reductions from the tax treatment of items related to plant, property and equipment as required by past MPSC orders, and by Part D of the Medicare Prescription Drug, Improvement and Modernization Act which provides a subsidy that is exempt from federal taxation.
For the year 2003 versus 2002, income tax expense increased primarily due to the tax treatment of items related to plant, property and equipment as required by past MPSC orders.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A:
- use of estimates and assumptions in accounting for contingencies and equity method investments,
- accounting for the effects of industry regulation,
- accounting for financial and derivative instruments and market risk information,
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- accounting for pension and OPEB,
- 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 of loss is probable and the amount of loss can be reasonably estimated. 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.
The cost that we incur under the MCV Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate that cash underrecoveries of capacity and fixed energy payments will aggregate $150 million from 2005 through 2007. After September 15, 2007, we expect to claim relief under the regulatory out provision in the PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts collected from our customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse effect on our investment, and
- eliminate our underrecoveries of capacity and fixed energy payments.
The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 2007 may affect negatively the earnings of the MCV Partnership and the value of our investment in the MCV Partnership.
Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. Even with the approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment.
In January 2005, the MPSC issued an order approving the RCP, with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility on the basis of natural gas market prices, which will reduce
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the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit our ownership interest in the MCV Partnership.
The substantial MCV Facility fuel cost savings will be used first to offset fully the cost of replacement power. Second, $5 million annually will be used to fund a renewable energy program. Remaining savings will be split between the MCV Partnership and Consumers. Consumers' direct savings will be shared 50 percent with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct savings from the RCP, after a portion is allocated to customers, will be used to offset our capacity and fixed energy underrecoveries expense. Since the MPSC has excluded these underrecoveries from the rate making process, we anticipate that our savings from the RCP will not affect our return on equity used in our base rate filings.
In January 2005, Consumers and the MCV Partnership's general partners accepted the terms of the order and implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed an application for rehearing of the MPSC order. The Attorney General also filed a claim of appeal with the Michigan Court of Appeals. We cannot predict the outcome of these appeals.
For additional details on the MCV Partnership, see Note 2, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity.
For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate they will require 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, 2004, we had $1.696 billion recorded as regulatory assets and $1.574 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 classified as available-for-sale are reported at fair value determined from quoted market prices. Debt and equity securities classified as held-to-maturity are reported at cost. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary.
Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our earnings or cash flows.
DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if certain contracts must be accounted for as derivative instruments. This criteria is complex and significant judgment is often required in applying the criteria to specific contracts. 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 is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in fair value (that is, gains or losses) are reported either in earnings or accumulated
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other comprehensive income, depending on whether the derivative qualifies for cash flow hedge accounting treatment.
The types of contracts we typically classify as derivative instruments are interest rate swaps, electric call options, gas supply call and put options, gas fuel futures and swaps, gas fuel options, and certain gas fuel contracts. The majority of our contracts are not subject to derivative accounting under SFAS No. 133 because they qualify for the normal purchases and sales exception, or because there is not an active market for the commodity. Our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market for the coal that we purchase. If active markets for these commodities develop in the future, we may be required to account for these contracts as derivatives, and the resulting mark-to-market impact on earnings could be material to our financial statements.
The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005, which will include day-ahead and real-time energy market information and centralized dispatch for market participants. At this time, we believe that the commencement of this market will not constitute the development of an active energy market in the state of Michigan. However, after having adequate experience with the Midwest Energy Market, we will reevaluate whether or not the activity level within this market leads to the conclusion that an active energy market exists. For additional information, see "Electric Business Uncertainties -- Competition and Regulatory Restructuring -- Transmission Market Developments" within this MD&A.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that certain of its long-term gas contracts qualify as normal purchases under SFAS No. 133, and therefore, these contracts are not recognized at fair value on the balance sheet. Due to the implementation of the RCP in January 2005, the MCV Partnership has determined that a significant portion of its gas fuel contracts no longer qualify as normal purchases because the contracted gas will not be consumed as fuel for electric production. Accordingly, these contracts will be treated as derivatives and will be marked-to-market through earnings each quarter, which could increase earnings volatility. Based on market prices for natural gas as of January 31, 2005, the accounting for the MCV Partnership's long-term gas contracts, including those affected by the implementation of the RCP, could result in an estimated $100 million (pretax before minority interest) gain recorded to earnings in the first quarter of 2005. This estimated gain will reverse in subsequent quarters as the contracts settle. For further details on the RCP, see "Critical Accounting Policies -- Use of Estimates and Assumptions -- MCV Underrecoveries" within this MD&A. If there are further changes in the level of planned electric production or gas consumption, the MCV Partnership may be required to account for additional long-term gas contracts as derivatives, which could add to earnings volatility.
To determine the fair value of our derivative contracts, we use a combination of quoted market prices, prices obtained from external sources, such as brokers, and mathematical valuation models. Valuation models require various inputs, including forward prices, strike prices, volatilities, interest rates, and maturity dates. Changes in forward prices or volatilities could change significantly the calculated fair value of certain contracts. At December 31, 2004, we assumed a market-based interest rate of 2.75 percent and monthly volatility rates ranging between 60 percent and 73 percent to calculate the fair value of our gas options. At December 31, 2004, we assumed market-based interest rates ranging between 2.40 percent and 4.48 percent (depending on the term of the contract) and monthly volatility rates ranging between 25 percent and 68 percent to calculate the fair value of the gas fuel derivative contracts held by the MCV Partnership.
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. In connection with the market valuation of our derivative contracts, we maintain reserves, if necessary, for credit risks based on the financial condition of counterparties.
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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 derivative contracts to manage these risks, including swaps, options, futures, and forward contracts. We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. We enter into all risk management contracts for purposes other than trading.
These contracts contain credit risk if the counterparties, including financial institutions and energy marketers, fail to perform under the agreements. We minimize such risk through established credit policies that include performing financial credit reviews of 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 and our current exposures, we do not anticipate a material adverse effect on our financial position or earnings as a result of counterparty nonperformance.
The following risk sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our derivative contracts and other financial instruments based upon a hypothetical 10 percent adverse change in market rates or prices. Changes in excess of the amounts shown in the sensitivity analyses could occur if market rates or prices exceed the 10 percent shift used for the analyses.
Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in market interest rates):
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(a) Fair value exposure could only be realized if we repurchased all of our fixed-rate financing.
Commodity Price Risk: For purposes other than trading, we enter into electric call options and gas supply call and put options. Electric call options are purchased to protect against the risk of fluctuations in the market price of electricity, and to ensure a reliable source of capacity to meet our customers' electric needs. Purchased electric call options give us the right, but not the obligation, to purchase electricity at predetermined fixed prices. Our gas supply call and put options are used to purchase reasonably priced gas supply. Purchases of gas supply call options give us the right, but not the obligation, to purchase gas supply at predetermined fixed prices. Gas supply put options sold give third-party suppliers the right, but not the obligation, to sell gas supply to us at predetermined fixed prices. At December 31, 2004, we held gas supply call options and had sold gas supply put options.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation and to manage gas fuel costs. Some of these contracts are treated as derivative instruments. The MCV Partnership also enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements.
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Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change in market prices):
We did not perform a sensitivity analysis for the derivative contracts held by the MCV Partnership as of December 31, 2003, because the MCV Partnership was not consolidated into our financial statements until 2004, as discussed in Note 13, Implementation of New Accounting Standards.
Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available-for-sale investments.
Investment Securities Price Risk Sensitivity Analysis:
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(a) Primarily SERP investments and investments in CMS Energy common stock.
(b) Assumes a 10 percent adverse change in market prices.
(c) Assumes a 50 basis point increase in the yield to maturity of the 10-year Treasury Note which approximates a 10 percent change in market yields.
We maintain trust funds, as required by the NRC, which may only be used to fund certain costs of nuclear plant decommissioning. As of December 31, 2004 and 2003, these funds were invested primarily in equity securities, fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are recorded at fair value on our Consolidated Balance Sheets. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear plant decommissioning recognizes that costs are recovered through our electric rates, fluctuations in equity prices or interest rates do not affect consolidated earnings or cash flows.
For additional details on market risk and derivative activities, see Note 4, Financial and Derivative Instruments.
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. We implemented a cash balance plan for certain employees hired after June 30, 2003. We use SFAS No. 87 to account for pension costs.
401(k): In our effort to reduce costs, the employer's match for the 401(k) plan was suspended effective September 1, 2002. The employer's match for the 401(k) plan resumed on January 1, 2005.
OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. We use SFAS No. 106 to account for other postretirement benefit costs.
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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 significantly change the liability and associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
Actual future pension cost and contributions will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the Pension Plan.
Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated pension cost for 2005 by $3 million. Lowering the discount rate by 0.25 percent (from 6.00 percent to 5.75 percent) would increase estimated pension cost for 2005 by $4 million.
For additional details on postretirement benefits, see Note 5, Retirement Benefits.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143 became effective January 2003. It requires companies to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. As required by SFAS No. 71, we accounted for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, gas transmission and electric and gas distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock are based on decommissioning studies that largely utilize third-party cost estimates. For additional details on ARO, see Note 6, Asset Retirement Obligations.
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ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our Big Rock and Palisades nuclear plants. We have established external trust funds to finance the decommissioning of both plants. We record the trust fund balances as a non-current asset on our Consolidated Balance Sheets.
Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent landscape,
- all contaminated equipment and material will be removed and disposed of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us develop decommissioning cost estimates. Various inflation rates for labor, non-labor, and contaminated equipment disposal costs are used to escalate these cost estimates to the future decommissioning cost. A portion of future decommissioning cost will result from the failure of the DOE to remove fuel from the sites, as required by the Nuclear Waste Policy Act of 1982.
The decommissioning trust funds include equities and fixed income investments. Equities will be converted to fixed income investments during decommissioning, and fixed income investments are converted to cash as needed. The funds provided by the trusts, additional customer surcharges, and potential funds from the DOE litigation are all required to cover fully the decommissioning costs. The costs of decommissioning these sites and the adequacy of the trust funds could be affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from customers, and
- changes in decommissioning technology, regulations, estimates, or assumptions.
Based on current projections, the current level of funds provided by the trusts is not adequate to fund fully the decommissioning of Big Rock or Palisades. This is due in part to the DOE's failure to accept the spent nuclear fuel on schedule and lower returns on the trust funds. We are attempting to recover our additional costs for storing spent nuclear fuel through litigation. We are also seeking additional relief from the MPSC. For additional details on nuclear decommissioning, see Note 2, Contingencies, "Other Electric Contingencies -- Nuclear Plant Decommissioning" and "Nuclear Matters."
RELATED PARTY TRANSACTIONS
We enter into a number of significant transactions with related parties. These transactions include:
- issuance of trust preferred securities with Consumers' affiliated companies,
- purchase and sale of electricity from and to Enterprises,
- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,
- payment of parent company overhead costs to CMS Energy, and
- investment in CMS Energy Common Stock.
Transactions involving CMS Energy and its affiliates generally are based on regulated prices, market prices, or competitive bidding. Transactions involving the power supply purchases from certain affiliates of Enterprises are based upon avoided costs under PURPA and competitive bidding. The payment of parent company overhead costs is based on the use of accepted industry allocation methodologies.
For additional details on related party transactions, see Note 1, Corporate Structure and Accounting Policies, "Related Party Transactions", and Note 2, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
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CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of operations, capital expenditures, contractual obligations, debt maturities, working capital needs, and collateral requirements. During the summer months, we purchase natural gas and store it for resale primarily during the winter heating season. The market price for natural gas has increased. Although our natural gas purchases are recoverable from our customers, the amount paid for natural gas stored as inventory could require additional liquidity due to the timing of the cost recoveries. In addition, a few of our commodity suppliers have requested nonstandard payment terms or other forms of assurances, including margin calls, in connection with maintenance of ongoing deliveries of gas and electricity.
Our current financial plan includes controlling our operating expenses and capital expenditures and evaluating market conditions for financing opportunities. We believe our current level of cash and access to borrowing capacity in the capital markets, along with anticipated cash flows from operating and investing activities, will be sufficient to meet our liquidity needs through 2006.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2004, $192 million consolidated cash was on hand, which includes $21 million of restricted cash and $126 million from the effect of Revised FASB Interpretation No. 46 consolidation. For additional details on cash equivalents and restricted cash, see Note 1, Corporate Structure and Accounting Policies. For additional details on FASB Interpretation No. 46, see Note 13, Implementation of New Accounting Standards.
SUMMARY OF CASH FLOWS:
OPERATING ACTIVITIES:
2004: Net cash provided by operating activities increased $635 million in 2004. The absence, in 2004, of $501 million in pension contributions made in 2003, the reduced effect of rising gas prices on inventory, and other timing differences represent the majority of the increase. These increases more than offset an increase in accounts receivable and accrued revenue resulting from higher gas prices.
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.
INVESTING ACTIVITIES:
2004: Net cash used in investing activities increased $34 million in 2004 primarily due to an increase in capital expenditures of $22 million. The increase in capital expenditures resulted from the consolidation of the MCV Partnership and the FMLP.
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.
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FINANCING ACTIVITIES:
2004: Net cash used in financing activities increased $452 million in 2004 primarily due to a decrease in net proceeds from borrowings of $699 million. This decrease was offset by a $250 million stockholder's contribution from the parent.
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.
SUBSEQUENT FINANCING ACTIVITIES:
In January 2005, we issued $250 million of 5.15 percent FMBs due 2017. We used the net proceeds of $247 million to pay off our $60 million long-term bank loan, to redeem our $73 million 8.36 percent subordinated deferrable interest notes, and to redeem our $124 million 8.20 percent subordinated deferrable interest notes. The subordinated deferrable interest notes are classified as Long-term debt -- related parties on our accompanying Consolidated Balance Sheets.
OBLIGATIONS AND COMMITMENTS
CONTRACTUAL OBLIGATIONS: The following table summarizes our contractual cash obligations for each of the periods presented. The table shows the timing and effect that such obligations are expected to have on our liquidity and cash flow in future periods. The table excludes all amounts classified as current liabilities on our Consolidated Balance Sheets, other than the current portion of long-term debt and capital and finance leases. The majority of current liabilities will be paid in cash in 2005.
CONTRACTUAL OBLIGATIONS AS OF DECEMBER 31, 2004
Long-Term Debt: The amounts in the table above represent the principal amounts due on outstanding debt obligations, current and long-term, as of December 31, 2004. For additional details on long-term debt, see Note 3, Financings and Capitalization.
Interest Payments on Long-term Debt: The amounts in the table above represent the currently scheduled interest payments on both variable and fixed rate long-term debt and long-term debt -- related parties, current and long-term. Variable interest payments are based on contractual rates in effect at December 31, 2004.
Capital and Finance Leases: The amounts in the table above represent the minimum lease payments payable under our capital and finance leases. They are comprised mainly of the leased portion of the MCV Partnership facility, leased service vehicles, and leased office furniture.
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Interest Payments on Capital and Finance Leases: The amounts in the table represent imputed interest in the capital leases and currently scheduled interest payments on the finance leases.
Operating Leases: The amounts in the table above represent the minimum noncancelable lease payments under our leases of railroad cars, certain vehicles, and miscellaneous office buildings and equipment, which are accounted for as operating leases.
Purchase Obligations: Long-term contracts for purchase of commodities and services are purchase obligations. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include:
- natural gas,
- electricity,
- coal and associated transportation, and
- electric transmission.
Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $14 million per month during 2005. 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, Contingencies, "Electric Rate Matters -- Power Supply Costs."
Long-term Service Agreements: These obligations of the MCV Partnership represent the cost of the current MCV Facility maintenance service agreements and cost of spare parts.
REVOLVING CREDIT FACILITIES: At December 31, 2004, we had $475 million available and the MCV Partnership had $48 million available in revolving credit facilities. The facilities are available for general corporate purposes, working capital, and letters of credit. For additional details on revolving credit facilities, see Note 3, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: We enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include letters of credit, surety bonds and indemnifications. For additional details on guarantee arrangements, see Note 3, Financings and Capitalization, "FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and in "Commercial Commitments" within this section.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we may sell up to $325 million of certain accounts receivable. For additional details, see Note 3, Financings and Capitalization.
COMMERCIAL COMMITMENTS: Our commercial contingent commitments include indemnities and letters of credit. Indemnities are agreements to reimburse other companies, such as an insurance company, if those companies have to complete our contractual performance in a third-party contract. Banks, on our behalf, issue letters of credit guaranteeing payment to a third party. Letters of credit substitute the bank's credit for ours and reduce credit risk for the third-party beneficiary. We monitor these obligations and believe it is unlikely that we
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would be required to perform or otherwise incur any material losses associated with these guarantees. Our off-balance sheet commitments at December 31, 2004 will expire as follows:
CONTINGENT COMMITMENTS
- ------------------------- (a) The surety bonds are continuous in nature. The need for the bonds is determined on an annual basis.
(b) The $2 million letter of credit for workers compensation self insurance and $5 million of MDEQ letters of credit are renewed annually.
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at December 31, 2004, we had $456 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim gas rate order, which included a $190 million annual dividend cap. For the year ended December 31, 2004, we paid $190 million in common stock dividends to CMS Energy.
CAPITAL EXPENDITURES: We estimate that we will make the following capital expenditures, including new lease commitments, by expenditure type and by business segments during 2005 through 2007. 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: In 2004, we experienced cooler than normal summer weather. As a result, our electric deliveries in 2004, including deliveries to customers who chose to buy generation service from alternative electric suppliers, increased less than one-half of one percent over the levels experienced in 2003. In 2005, we project electric deliveries to grow almost three percent. This short-term outlook for 2005 assumes a stronger economy than in 2004 and normal weather conditions throughout the year.
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Over the next five years, we expect electric deliveries to grow at an average rate of approximately two percent per year, based primarily on a steadily growing customer base and economy. This growth rate includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. This growth rate reflects a long-range expected trend of growth. Growth from year to year may vary from this trend due to customer response to fluctuations in weather conditions and changes in economic conditions, including utilization and expansion of manufacturing facilities.
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/or Clear Skies legislation compliance,
- compliance with legislative proposals that would require reductions in emissions of greenhouse gases, 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,
- recovery of our Section 10d(4) Regulatory Assets,
- effects of lost electric supply load to alternative electric suppliers, and
- status as an electric transmission customer instead of an electric transmission owner and the impact of the evolving RTO infrastructure.
Regulatory
- financial and operating effects of regulatory requirements imposed by the MISO, the FERC, state and federal regulators, or others, seeking to improve reliability of national and state transmission systems,
- inadequate regulatory response to applications for requested rate increases,
- responses from regulators regarding the storage and ultimate disposal of spent nuclear fuel,
- recovery of nuclear decommissioning costs. For additional details, see "Accounting for Nuclear Decommissioning Costs" within this MD&A, and
- potential for the Midwest Energy Market to develop into an active energy market in the state of Michigan and the potential derivative accounting impact. For additional details, see "Accounting for Financial and Derivative Instruments and Market Risk Information" within this MD&A.
Other
- effects of commodity fuel prices such as natural gas, oil, and coal,
- pending litigation filed by PURPA qualifying facilities, and
- other pending litigation.
For additional details about these trends or uncertainties, see Note 2, Contingencies.
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ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.
Clean Air: Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for us. The Title I provisions of the Clean Air Act require significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $802 million. The key assumptions included in the capital expenditure estimate include:
- construction commodity prices, especially construction material and labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.06 percent. As of December 31, 2004, we have incurred $525 million in capital expenditures to comply with these regulations and anticipate that the remaining $277 million of capital expenditures will be made between 2005 and 2011. These expenditures include installing selective catalytic reduction technology at four of our coal-fired electric plants. In addition to modifying the coal-fired electric plants, we expect to utilize nitrogen oxide emissions allowances for years 2005 through 2009, most of which have been purchased. The cost of the allowances is estimated to average $8 million per year for 2005-2006. The need for allowances will decrease after year 2006 with the installation of emissions control technology. The cost of the allowances is accounted for as inventory. The allowance inventory is expensed as the coal-fired electric generating units emit nitrogen oxide.
The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits from the EPA. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of "routine maintenance." If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question.
The EPA has proposed a Clean Air Interstate Rule that would require additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. If implemented, this rule potentially would require expenditures equivalent to those efforts in progress to reduce nitrogen oxide emissions as required under the Title I provisions of the Clean Air Act. The rule proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent and nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two alternative sets of rules to reduce emissions of mercury from coal-fired electric plants and nickel from oil-fired electric plants. Until the proposed environmental rules are finalized, an accurate cost of compliance cannot be determined.
Our switch to western coal as a primary fuel source has resulted in reduced plant emissions and increased our flexibility in meeting future regulatory compliance requirements. Excess sulfur dioxide allowances optimize our overall cost of regulatory compliance by delaying capital expenditures and minimizing regulatory uncertainty. Additionally, the excess sulfur dioxide allowances can be used to trade for nitrogen oxide allowances supplementing our nitrogen oxide allowance bank. Western coal has reduced our overall cost of fuel and reduced the economic impact from the recent increases in eastern coal prices.
Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, however, none have yet been enacted. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any such rules.
To the extent that greenhouse gas emission reduction rules come into effect, such mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sectors. We cannot estimate the potential effect of federal or state level greenhouse gas policy on our future consolidated results of
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operations, cash flows, or financial position due to the speculative nature of the policies at this time. However, we stay abreast of and engage in the greenhouse gas policy developments and will continue to assess and respond to their potential implications on our business operations.
Water: In March 2004, the EPA issued rules that govern generating plant cooling water intake systems. The new rules require significant reduction in fish killed by operating equipment. Some of our facilities will be required to comply with the new rules by 2006. We are currently studying the rules to determine the most cost-effective solutions for compliance.
For additional details on electric environmental matters, see Note 2, Contingencies, "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. The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. As of March 2005, alternative electric suppliers are providing 900 MW of generation supply to ROA customers. This amount represents 12 percent of our distribution load and an increase of 23 percent compared to March 2004. Based on current trends, we predict total load loss by the end of 2005 to be in the range of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load loss will fall within that range.
In July 2004, as a result of legislative hearings, several bills were introduced into the Michigan Senate that could change Michigan's Customer Choice Act. The proposals include:
- requiring that all rate classes of regulated utilities be based on cost of service,
- establishing a defined Stranded Cost calculation method,
- allowing customers who stay with or switch to alternative electric suppliers after December 31, 2005 to return to utility services, and requiring them to pay current market rates upon return,
- establishing reliability standards that all electric suppliers must follow,
- requiring utilities and alternative electric suppliers to maintain a 15 percent power reserve margin,
- creating a service charge to fund the Low Income and Energy Efficiency Fund,
- giving kindergarten through twelfth-grade schools a discount of 10 percent to 20 percent on electric rates, and
- authorizing a service charge payable by all customers for meeting Clean Air Act requirements.
This legislation was not enacted before the end of the 2003-2004 legislative session. We anticipate that some or all of the bills may be reintroduced in the 2005-2006 legislative session. We cannot predict the outcome of these legislative proceedings.
Implementation Costs: Applications for recovery of $7 million of implementation costs for 2002 and $1 million for 2003 are pending MPSC approval. In September 2004, the ALJ issued a Proposal for Decision recommending full recovery of these costs.
We are also pursuing authorization at the FERC for the MISO to reimburse us for approximately $8 million of Alliance RTO development costs. Included in this amount is $5 million pending approval by the MPSC as part of our 2002 implementation costs application. The FERC has denied our request for reimbursement and we are appealing the FERC ruling at the United States Court of Appeals for the District of Columbia. Although we believe these implementation costs are fully recoverable in accordance with the Customer Choice Act, we cannot predict the amount, if any, the MPSC or the FERC will approve as recoverable.
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze and rate cap periods, including the cost of
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money. In October 2004, we filed an application with the MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets for the period June 2000 through December 2005 consisting of:
- capital expenditures in excess of depreciation,
- Clean Air Act costs,
- other expenses related to changes in law or governmental action incurred during the rate freeze and rate cap periods, and
- the associated cost of money through the period of collection.
Of the $628 million, $152 million relates to the cost of money. In March 2005, the MPSC Staff filed testimony recommending the MSPC approve recovery of approximately $323 million. We cannot predict the amount, if any, the MPSC will approve as recoverable.
Rate Caps: The Customer Choice Act imposes certain limitations on electric rates that could result in our inability to collect our full cost of conducting business from electric customers. Rate caps are effective through December 31, 2005 for residential customers. As a result, we may be unable to maintain our profit margins in our electric utility business during the rate cap period. In particular, if we need to purchase power supply from wholesale suppliers while retail rates are capped, the rate restrictions may preclude full recovery of purchased power and associated transmission costs.
Power Supply Costs: To reduce the risk of high electric prices during peak demand periods and to achieve our reserve margin target, we employ a strategy of purchasing electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We are currently planning for a reserve margin of approximately 11 percent for summer 2005, or supply resources equal to 111 percent of projected summer peak load. Of the 2005 supply resources target of 111 percent, we expect to meet approximately 102 percent from our electric generating plants and long-term power purchase contracts, and approximately 9 percent from short-term contracts, options for physical deliveries, and other agreements. We have purchased capacity and energy contracts partially covering the estimated reserve margin requirements for 2005 through 2007. As a result, we have recognized an asset of $12 million for unexpired capacity and energy contracts as of December 31, 2004.
PSCR: The PSCR process assures recovery of all reasonable and prudent power supply costs actually incurred by us. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from other customers. We self-implemented the proposed 2005 PSCR charge in January 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings.
Special Contracts: We entered into multi-year electric supply contracts with certain industrial and commercial customers. The contracts provide electricity at specially negotiated prices that are at a discount from tariff prices, but above our incremental cost of service. As of February 2005, special contracts for approximately 630 MW of load are in place, most of which are in effect through 2005. We cannot predict the amount of electric load from these customers that will continue with our electric service after their contracts expire.
Transmission Costs: In May 2002, we sold our electric transmission system for $290 million to MTH. We are in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized by approximately $2 million to $3 million.
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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 rulemaking could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
In November 2004, the FERC ruled on MISO and PJM RTO "through and out" rates. Through and out rates are applied to transmission transactions when a transmission customer purchases electricity that travels through multiple transmission pricing zones. Effective December 1, 2004, regional through and out rates for transactions between the PJM RTO and the MISO were eliminated by the FERC. In that November 2004 order, the FERC conditionally accepted, for a period beginning December 1, 2004 and ending January 31, 2008, a "license plate" pricing structure. License plate pricing provides for access to the combined regional transmission systems of the PJM RTO and the MISO at a single rate, although the rate may vary based on where the customer's load is located.
The order also adopts a transitional charge from December 1, 2004 through March 31, 2006, intended to mitigate abrupt cost shifts between transmission owners and customers as a result of the pricing structure change. The manner in which these transitional charges are calculated and implemented is currently the subject of multiple disputes pending at the FERC. Based on the compliance filings with the FERC made by the MISO and PJM RTO transmission owners, the new transitional charges will not have a significant impact on our electric results of operations. However, we cannot predict the outcome of the disputes concerning these transitional charges pending at the FERC.
Transmission Market Developments: The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005. At that time, the MISO will implement a day-ahead and real-time energy market and centralized dispatch for the MISO's market participants. These changes are anticipated to ensure that load requirements in the region are met reliably and efficiently, to better manage congestion on the grid, and to produce consumer savings through the centralized dispatch of generation throughout the region. The MISO is expected to provide other functions, including long-term regional planning and market monitoring.
In addition, we are evaluating whether or not there may be impacts on electric reliability associated with changes in the composition of transmission markets. For example, Commonwealth Edison Company joined the PJM RTO in May 2004 and American Electric Power Service Corporation joined the PJM RTO in October 2004. These integrations may be creating different patterns of power flow within the Midwest area and could affect adversely our ability to provide reliable service to our customers. We are presently evaluating what financial impacts, if any, these market developments are having on our operations.
August 14, 2003 Blackout: The NERC and the U.S. and Canadian Power System Outage Task Force have released electric operations recommendations resulting from their investigation into the August 14, 2003 blackout. Few of the recommendations apply directly to us, since we are not a transmission owner. However, the recommendations could result in increased transmission costs to us and require upgrades to our distribution system. We cannot quantify the financial impact of these recommendations at this time.
For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 2, Contingencies, "Electric Restructuring Matters," and "Electric Rate Matters."
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to increase our retail electric base rates. The electric rate case filing requests an annual increase in revenues of approximately $320 million. The primary reasons for the request are increased system maintenance and improvement costs, Clean Air Act related expenditures, and employee pension costs. A final order from the MPSC on our electric rate case is expected in late 2005. If approved as requested, the rate increase would go into effect in January 2006 and would apply to all retail electric customers. We cannot predict the amount or timing of the rate increase, if any, which the MPSC will approve.
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BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of Appeals upheld a lower court decision that requires Detroit Edison to obey a municipal ordinance enacted by the City of Taylor, Michigan. The ordinance requires Detroit Edison to bury a section of its overhead power lines at its own expense. Detroit Edison has filed an appeal with the Michigan Supreme Court. Unless overturned by the Michigan Supreme Court, the decision could encourage other municipalities to adopt similar ordinances, as has occurred or is being discussed in a few municipalities in Consumers' service territory. If incurred, we would seek recovery of these costs from our customers, subject to MPSC approval. This case has potentially broad ramifications for the electric utility industry in Michigan; however, at this time, we cannot predict the outcome of this matter.
OTHER ELECTRIC BUSINESS UNCERTAINTIES
NUCLEAR MATTERS:
Big Rock: Dismantlement of plant systems is essentially complete and demolition of the remaining plant structures has begun. The restoration project is on schedule to return approximately 530 acres of the site, including the area formerly occupied by the nuclear plant, to a natural setting for unrestricted use in mid-2006. An additional 30 acres, the area where seven transportable dry casks loaded with spent nuclear fuel and an eighth cask loaded with high-level radioactive waste material are stored, will be returned to a natural state by the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.
Palisades: In August 2004, the NRC completed its mid-cycle plant performance assessment of Palisades. The assessment for Palisades covered the first half of 2004. The NRC determined that Palisades was operated in a manner that preserved public health and safety and fully met all cornerstone objectives. As of December 2004, all inspection findings were classified as having very low safety significance and all performance indicators show performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through March 2006.
The amount of spent nuclear fuel at Palisades exceeds the plant's temporary onsite storage pool capacity. We are using dry casks for temporary onsite storage. As of December 31, 2004, we have loaded 22 dry casks with spent nuclear fuel. For additional information on disposal of spent nuclear fuel, see Note 2, Contingencies, "Other Electric Contingencies -- Nuclear Matters."
In September 2004, we announced that we will seek a license renewal for the Palisades plant. The plant's current license from the NRC expires in 2011. NMC, which operates the facility, will apply for a 20-year license renewal for the plant on behalf of Consumers. The Palisades renewal application is scheduled to be filed by the end of the first quarter of 2005.
We have authorized the purchase of a replacement reactor vessel closure head. The replacement head is being manufactured and scheduled to be installed in 2007. Palisades, like many other nuclear plants, has experienced cracking in reactor head nozzle penetrations. Repairs to two nozzles were made in 2004. The replacement head nozzles will be manufactured from materials less susceptible to cracking and should minimize inspection and repair costs after replacement.
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council, the Public Interest Research Group in Michigan, and the Michigan Consumer Federation filed a complaint with the MPSC, which was served on us by the MPSC in April 2003. The complaint asks the MPSC to initiate a generic investigation and contested case to review all facts and issues concerning costs associated with spent nuclear fuel storage and disposal. The complaint seeks a variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service Corporation. The complaint states that amounts collected from customers for spent nuclear fuel storage and disposal should be placed in an independent trust. The complaint also asks the MPSC to take additional actions. In May 2003, Consumers and other named utilities each filed motions to dismiss the complaint. We are unable to predict the outcome of this matter.
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GAS BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an average rate of less than one percent per year. Actual gas deliveries in future periods may be affected by:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the MPSC for a Certificate of Public Convenience and Necessity to construct a 25-mile gas transmission pipeline in northern Oakland County. The project is necessary to meet estimated peak load beginning in the winter of 2005 through 2006. In December 2004, the MPSC approved a settlement agreement authorizing us to construct and operate the pipeline. Construction is expected to begin late spring of 2005.
In October 2004, we filed an application with the MPSC for a Certificate of Public Convenience and Necessity to construct a 10.8-mile gas transmission pipeline in northwestern Wayne County. The project is necessary to meet the projected capacity demands beginning in the winter of 2007. If we are unable to construct the pipeline, we will need to pursue more costly alternatives or curtail serving the system's load growth in that area.
GAS BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial results and conditions. These trends or uncertainties could have a material impact on revenues or income from gas operations. The trends and uncertainties include:
Regulatory
- inadequate regulatory response to applications for requested rate increases,
- response to increases in gas costs, including adverse regulatory response and reduced gas use by customers, and
- proposed distribution pipeline integrity rules and mandates.
Environmental
- potential environmental remediation costs at a number of sites, including sites formerly housing manufactured gas plant facilities.
Other
- transmission pipeline integrity mandates, maintenance and remediation costs, and
- other pending litigation.
GAS TITLE TRACKING FEES AND SERVICES: On February 14, 2005, the FERC issued its latest order involving Consumers' Gas Title Transfer Tracking Fees and Services. In doing so, the FERC agreed with us that such orders only apply to a title transfer tracking fee charged and collected in connection with the Consumers' FERC blanket transportation service. Because of the newly stated limits on what fees are subject to refund, we believe that if any such refunds are ultimately required, they will not be material.
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GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs for prudency in an annual reconciliation proceeding.
The following table summarizes our GCR reconciliation filings with the MPSC. For additional details, see Note 2, Contingencies, "Gas Rate Matters--Gas Cost Recovery."
GAS COST RECOVERY RECONCILIATION
Net over-recovery amounts included in the table above include refunds that we received from our suppliers that are required to be refunded to our customers.
GCR Year 2003-2004: In February 2005, the MPSC approved a settlement agreement that resulted in a credit to our GCR customers for a $28 million over-recovery, plus $3 million interest, using a roll-in refund methodology. The roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan year.
GCR Plan for Year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
GCR Plan for Year 2005-2006: In December 2004, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2005 through March 2006. Our request proposes using a GCR factor consisting of:
- a base GCR factor of $6.98 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future events.
The GCR factor can be adjusted monthly, provided it remains at or below the current ceiling price. The quarterly adjustment mechanism allows an increase in the GCR ceiling price to reflect a portion of cost increases if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. In December 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes.
On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon our agreement to:
- achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached,
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- make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted,
- refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate,
- prepare and file annual reports that address certain issues identified in the order, and
- file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect).
On October 15, 2004, we agreed to these commitments.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003, the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case.
In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case. The October 2004 order requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. The MPSC also directed us to undertake a study to determine why our removal costs are in excess of those of other regulated Michigan natural gas utilities and file a report with the MPSC Staff on or before December 31, 2005.
In February 2005, we requested a delay in the filing date for the next depreciation case until after the MPSC considers the removal cost study, and after the MPSC issues an order in a pending case relating to asset retirement obligation accounting.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. We expect our remaining remedial action costs to be between $37 million and $90 million. We expect to fund most of these costs through insurance proceeds and through the MPSC approved rates charged to our customers. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs. For additional details, see Note 2, Contingencies, "Gas Contingencies -- Gas Environmental Matters."
OTHER OUTLOOK
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $10 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore, the above refund (net of approximately $16 million of deferred expenses) has not been recognized in 2004 earnings.
COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees are represented by the Utility Workers of America Union. The Union represents Consumers' operating, maintenance, and construction employees and our call center employees. The collective bargaining agreement with the Union for our operating, maintenance, and construction employees will expire on June 1, 2005 and negotiations for a new agreement is underway currently. The collective bargaining agreement with the Union for our call center employees will expire on August 1, 2005.
LITIGATION AND REGULATORY INVESTIGATION: CMS Energy is the subject of various investigations as a result of round-trip trading transactions by CMS MST, including an investigation by the DOJ. Additionally, CMS Energy and Consumers are named as parties in various litigation matters including a shareholder derivative
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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, Contingencies.
NEW ACCOUNTING STANDARDS
For a discussion of new pronouncements, see Note 13, Implementation of New Accounting Standards.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to expense the grant date fair value of employee stock options and similar awards. The Statement also clarifies and expands SFAS No. 123's guidance in several areas, including measuring fair value, classifying an award as equity or as a liability, and attributing compensation cost to reporting periods.
In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to require that excess tax benefits related to the excess of the tax deductible amount over the compensation cost recognized be classified as a financing cash inflow rather than as a reduction of taxes paid in operating activities.
This Statement is effective for us as of the beginning of third quarter 2005. We adopted the fair value method of accounting for share-based awards effective December 2002, and therefore, expect this statement to have an insignificant impact on our results of operations when it becomes effective.
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CONSUMERS ENERGY COMPANY
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Consumers' management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. Under the supervision and with the participation of management, including its CEO and CFO, Consumers conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, Consumers' management concluded that its internal control over financial reporting was effective as of December 31, 2004.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Consumers' management's assessment of the effectiveness of Consumers' internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, who audited the consolidated financial statements of Consumers included in this Form 10-K. Ernst & Young LLP's attestation report on Consumers' management's assessment of internal control over financial reporting follows this report.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder of Consumers Energy Company
We have audited management's assessment, included in MANAGEMENT'S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING, that Consumers Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Consumers Energy Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the company's internal control over financial reporting based on our audit. We did not examine the effectiveness of internal control over financial reporting of Midland Cogeneration Venture Limited Partnership, a 49% owned variable interest entity which has been consolidated pursuant to Revised Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities", whose financial statements reflect total assets and revenues constituting 15% and 14%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004. The effectiveness of Midland Cogeneration Venture Limited Partnership's internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the effectiveness of Midland Cogeneration Venture Limited Partnership's internal control over financial reporting, is based solely on the report of the other auditors.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit and the report of the other auditors provide a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, based on our audit and the report of the other auditors, management's assessment that Consumers Energy Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, based on our audit and the report of the other auditors, Consumers Energy Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Consumers Energy Company and subsidiaries as of December 31, 2004 and 2003, 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, 2004 and our report dated March 7, 2005 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Detroit, Michigan March 7, 2005
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MCV MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
MCV's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting of MCV. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
MCV's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of MCV; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of MCV are being made only in accordance with authorizations of management and the Management Committee of MCV; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of MCV's assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. Our system contains self-monitoring mechanisms, and actions are taken to correct deficiencies as they are identified.
MCV management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the framework in "Internal Control -- Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that MCV's system of internal control over financial reporting was effective as of December 31, 2004. MCV management's assessment of the effectiveness of MCV's internal control over financial reporting has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
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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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The accompanying notes are an integral part of these statements. CE-37
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
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The accompanying notes are an integral part of these statements. CE-39
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 Other Comprehensive Income:
The accompanying notes are an integral part of these statements. CE-41
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: Consumers, a subsidiary of CMS Energy, a holding company, is a combination electric and gas utility company that provides service to customers in Michigan's Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers, the largest segment of which is the automotive industry.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include Consumers, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with Revised FASB Interpretation No. 46. The primary beneficiary of a variable interest entity is the party that absorbs or receives a majority of the entity's expected losses or expected residual returns or both as a result of holding variable interests, which are ownership, contractual, or other economic interests. In 2004, we consolidated the MCV Partnership and the FMLP in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 13, Implementation of New Accounting Standards. These entities are reported as equity method investments in our consolidated financial statements for all periods prior to January 1, 2004. We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. Intercompany transactions and balances have been eliminated.
USE OF ESTIMATES: We prepare our consolidated financial statements in conformity with U.S. generally accepted accounting principles. 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 consolidated financial statements when it is probable that a loss will be incurred in the future as a result of a current event, and when the amount can be reasonably estimated. We have used this accounting principle to record estimated liabilities as discussed in Note 2, Contingencies.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the storage of natural gas when services are provided. Sales taxes are recorded as liabilities and are not included in revenues.
CAPITALIZED INTEREST: We are required to capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest for the period is limited to the actual interest cost that is incurred. Our regulated businesses are permitted to capitalize an allowance for funds used during construction on regulated construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an original maturity of three months or less are considered cash equivalents.
At December 31, 2004, our restricted cash on hand was $21 million. Restricted cash dedicated for repayment of Securitization bonds is classified as a current asset as the payments on the related Securitization bonds occur within one year.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities using SFAS No. 115. Debt and equity securities classified as available-for-sale are reported at fair value determined from quoted market prices. Debt and equity securities classified as held-to-maturity are reported at cost. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of accumulated other comprehensive income. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary.
Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our earnings or cash flows.
For additional details regarding financial instruments, see Note 4, Financial and Derivative Instruments. CE-43
CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
GAS INVENTORY: We use the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities
GENERATING PLANT FUEL STOCK INVENTORY: We use the weighted average cost method for valuing coal inventory and classify these costs as generating plant fuel stock on our Consolidated Balance Sheets. The MCV Partnership's natural gas inventory is also included in this category, stated at the lower of cost or market and valued using the last-in, first-out ("LIFO") method.
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 its estimated undiscounted future 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 represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements. We depreciate utility property using straight-line rates approved by the MPSC. The composite depreciation rates for our properties are:
NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on the quantity of heat produced for electric generation. For nuclear fuel used after April 6, 1983, we charge certain disposal costs to nuclear fuel expense, recover these costs through electric rates, and remit them to the DOE quarterly. We elected to defer payment for disposal of spent nuclear fuel burned before April 7, 1983. As of December 31, 2004, we have recorded a liability to the DOE of $141 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, Contingencies, "Other Electric Contingencies -- Nuclear Matters."
OTHER INCOME AND OTHER EXPENSE: The following tables show the components of Other income and Other expense:
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at original cost when placed into service. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost is charged to accumulated depreciation. The cost of removal, less salvage, is recorded as a regulatory liability. For additional details, see Note 6, Asset Retirement Obligations. An allowance for funds used during construction is capitalized on regulated construction projects. With respect to the retirement or disposal of non-regulated assets, the resulting gains or losses are recognized in income.
Property, plant, and equipment at December 31, 2004 and 2003, was as follows:
- ------------------------- (a) Capital leases presented in this table are gross amounts. Accumulated amortization of capital leases was $49 million at December 31, 2004 and $38 million at December 31, 2003.
(b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2004 and $23 million at December 31, 2003, which is not subject to depreciation.
(c) As of December 31, 2004, accumulated depreciation, depletion, and amortization is comprised of $4.601 billion from public utility plant, $1.063 billion related to the consolidation of the MCV Facility, and $1 million from our non-utility plant assets. As of December 31, 2003, accumulated depreciation, depletion,
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
and amortization included $4.416 billion from our public utility plant and $1 million related to non-utility plant assets.
(d) Included in net property, plant and equipment are intangible assets primarily related to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization life for software development costs is seven years. The estimated amortization life for leasehold improvements is over the life of the lease. Other intangible amortization lives range from 50 to 105 years. Intangible assets at December 31, 2004 and 2003 were as follows:
Pre-tax amortization expense related to these intangible assets was $19 million for the year ended December 31, 2004, $19 million for the year ended December 31, 2003, and $17 million for the year ended December 31, 2002. Intangible assets amortization is forecasted to range from $8 million to $19 million per year over the next five years.
(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.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
RELATED PARTY TRANSACTIONS: We received income from related parties as follows:
We recorded expense from related parties as follows:
- ------------------------- (a) In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 13, Implementation of New Accounting Standards.
(b) 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 13, Implementation of New Accounting Standards.
(c) We base our related party transactions on regulated prices, market prices, or competitive bidding. In 2003, we paid overhead costs to CMS Energy based on an industry allocation methodology, such as the Massachusetts Formula. In 2004, we paid no overhead costs to CMS Energy.
(d) Panhandle was sold in June 2003.
We own 2.4 million shares of CMS Energy Common Stock with a fair value of $25 million at December 31, 2004. For additional details on our investment in CMS Energy Common Stock, see Note 4, Financial and Derivative Instruments.
TRADE RECEIVABLES: We record our accounts receivable at fair value. Accounts deemed uncollectible are charged to operating expense.
UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums, discounts, and expenses incurred in connection with the issuance of long-term debt and amortize those costs ratably over the terms of the debt issues. Any refinancing costs are charged to expenses as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and expenses and amortize them ratably over the terms of the newly issued debt.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets. We expect to recover these costs through rates over periods of up to 14 years. We recognized an OPEB transition obligation in accordance with SFAS No. 106 and established a regulatory asset for the amount that we expect to recover in rates over the next eight years.
- ------------------------- (a) At December 31, 2004, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.677 billion of regulatory assets as non-current regulatory assets. At December 31, 2003, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.086 billion of regulatory assets as non-current regulatory assets. At December 31, 2004 and December 31, 2003, all of our regulatory liabilities represented non-current regulatory liabilities.
2: CONTINGENCIES
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 implemented the recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of securities class action complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates. The complaints were filed as purported class actions in the United States District Court for the Eastern District of Michigan, by shareholders who allege that they purchased CMS Energy's securities during a purported class period. These cases were later consolidated by the court. The plaintiffs generally seek 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 the individual defendants filed motions to dismiss on June 21, 2004. The judge issued an opinion and order dated January 7, 2005, granting the motion to dismiss for Consumers and three of the individual defendants, but denying the motions to dismiss for CMS Energy and the 13 remaining individual defendants. CMS Energy and the individual defendants will defend themselves vigorously but cannot predict the outcome of this litigation.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST, and certain named and unnamed officers and directors, in two lawsuits brought as purported class actions on behalf of participants and beneficiaries of the CMS Employees' Savings and Incentive Plan (the "Plan"). The two cases were filed in July 2002 in United States District Court for the Eastern District of Michigan and were later consolidated by the court. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge issued an opinion and order dated December 27, 2004, conditionally granting plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than late in 2005. CMS Energy and Consumers will defend themselves vigorously but cannot predict the outcome of this litigation.
ELECTRIC CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.
Clean Air: The EPA and the state regulations require us to make significant capital expenditures estimated to be $802 million. As of December 31, 2004, we have incurred $525 million in capital expenditures to comply with the EPA regulations and anticipate that the remaining $277 million of capital expenditures will be made between 2005 and 2011.
The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seek modification permits from the EPA. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of "routine maintenance." If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question.
In addition to modifying the coal-fired electric plants, we expect to utilize nitrogen oxide emissions allowances for years 2005 through 2009, most of which have been purchased. The cost of the allowances is estimated to average $8 million per year for 2005-2006. The need for allowances will decrease after year 2006 with the installation of emissions control technology.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 2004, we have recorded a liability for the minimum amount of our estimated Superfund liability.
In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at the Ludington Pumped Storage facility. We removed and replaced part of the PCB material. We have proposed a plan to deal with the remaining materials and are awaiting a response from the EPA.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit alleges that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. In February 2004, the Ingham County Circuit Court judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The eight plaintiff qualifying facilities have appealed the dismissal of the circuit court case to the Michigan Court of Appeals. We cannot predict the outcome of this appeal.
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms, and conditions under which retail customers are permitted to choose an electric supplier. These revised tariffs allow ROA customers, upon as little as 30 days notice to us, to return to our generation service at current tariff rates. If any class of customers' (residential, commercial, or industrial) ROA load reaches ten percent of our total load for that class of customers, then returning ROA customers for that class must give 60 days notice to return to our generation service at current tariff rates. However, we may not have capacity available to serve returning ROA customers that is sufficient or reasonably priced. As a result, we may be forced to purchase electricity on the spot market at higher prices than we can recover from our customers during the rate cap periods. We cannot predict the total amount of electric supply load that may be lost to alternative electric suppliers. As of March 2005, alternative electric suppliers are providing 900 MW of generation supply to ROA customers. This amount represents 12 percent of our distribution load and an increase of 23 percent compared to March 2004.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric restructuring proceedings.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following chart summarizes our electric restructuring filings with the MPSC:
- ------------------------- (a) Amount includes the cost of money through the year in which we expected to receive recovery from the MPSC and assumes recovery of Clean Air Act costs through the Section 10d(4) Regulatory Asset case.
(b) Amount includes the cost of money through the year prior to the year filed.
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act allows us to recover certain regulatory assets through deferred recovery of annual capital expenditures in excess of depreciation levels and certain other expenses incurred prior to and throughout the rate freeze and rate cap periods, including the cost of money. The section also allows deferred recovery of expenses incurred during the rate freeze and rate cap periods that result from changes in taxes, laws, or other state or federal governmental actions. In October 2004, we filed an application with the MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets for the period June 2000 through December 2005 consisting of:
- capital expenditures in excess of depreciation,
- Clean Air Act costs,
- other expenses related to changes in law or governmental action incurred during the rate freeze and rate cap periods, and
- the associated cost of money through the period of collection.
Of the $628 million, $152 million relates to the cost of money.
As allowed by the Customer Choice Act, in January 2004, we began accruing and deferring for recovery the 2004 portion of our Section 10d(4) Regulatory Assets. In November 2004, the MPSC issued an order in Detroit Edison's general electric rate case which concluded that Detroit Edison's return of and on Clean Air Act costs incurred from June 2000 through December 2003 are recoverable under Section 10d(4). Based on the precedent set by this order, we recorded an additional regulatory asset in November 2004 for our return of and on Clean Air Act expenditures incurred from 2000 through 2003. Unless we receive an order from the MPSC to the contrary, we will continue to record additional accruals. However, certain aspects of Detroit Edison's electric rate case are different from our Section 10d(4) Regulatory Asset filing. In March 2005, the MPSC Staff filed testimony recommending the MPSC approve recovery of approximately $323 million. We cannot predict the amount, if any,
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
the MPSC will approve as recoverable. At December 31, 2004, total Section 10d(4) Regulatory Assets totaled $141 million.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system to MTH, a non-affiliated limited partnership whose general partner is a subsidiary of Trans-Elect, Inc. We are in arbitration with MTH regarding property tax items used in establishing the selling price of our electric transmission system. An unfavorable outcome could result in a reduction of sale proceeds previously recognized of approximately $2 million to $3 million.
ELECTRIC RATE MATTERS
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to increase our retail electric base rates. The electric rate case filing requests an annual increase in revenues of approximately $320 million. The primary reasons for the request are increased system maintenance and improvement costs, Clean Air Act related expenditures, and employee pension costs. A final order from the MPSC on our electric rate case is expected in late 2005. If approved as requested, the rate increase would go into effect in January 2006 and would apply to all retail electric customers. We cannot predict the amount or timing of the rate increase, if any, which the MPSC will approve.
POWER SUPPLY COSTS: To reduce the risk of high electric prices during peak demand periods and to achieve our reserve margin target, we employ a strategy of purchasing electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We have purchased capacity and energy contracts partially covering the estimated reserve margin requirements for 2005 through 2007. As a result, we have recognized an asset of $12 million for unexpired capacity and energy contracts as of December 31, 2004. The total premium costs of electric capacity and energy contracts for 2004 were approximately $12 million.
PSCR: The PSCR process assures recovery of all reasonable and prudent power supply costs actually incurred by us. In September 2004, we submitted our 2005 PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a portion of our increased power supply costs from commercial and industrial customers and, subject to the overall rate caps, from other customers. We self-implemented the proposed 2005 PSCR charge in January 2005. We estimate the increased recovery of power supply costs from commercial and industrial customers to be approximately $49 million in 2005. The revenues from the PSCR charges are subject to reconciliation at the end of the year after actual costs have been reviewed for reasonableness and prudence. We cannot predict the outcome of these PSCR proceedings.
OTHER ELECTRIC CONTINGENCIES
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 a 49 percent partnership interest in the MCV Partnership, and a 35 percent lessor interest in the MCV Facility.
In 2004, we consolidated the MCV Partnership and the FMLP into our consolidated financial statements in accordance with Revised FASB Interpretation No. 46. For additional details, see Note 13, Implementation of New Accounting Standards. Our consolidated retained earnings include undistributed earnings from the MCV Partnership of $237 million at December 31, 2004 and $245 million at December 31, 2003.
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The cost that we incur under the MCV Partnership PPA exceeds the recovery amount allowed by the MPSC. We expense all cash underrecoveries directly to income. We estimate cash underrecoveries of capacity and fixed energy payments as follows:
After September 15, 2007, we expect to claim relief under the regulatory out provision in the PPA, limiting our capacity and fixed energy payments to the MCV Partnership to the amount collected from our customers. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 15, 2007 may affect negatively the earnings of the MCV Partnership and the value of our investment in the MCV Partnership.
Further, under the PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at our coal plants and our operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Because natural gas prices have increased substantially in recent years and the price the MCV Partnership can charge us for energy has not, the MCV Partnership's financial performance has been impacted negatively. Even with the approved RCP, if gas prices continue at present levels or increase, the economics of operating the MCV Facility may be adverse enough to require us to recognize an impairment.
In January 2005, the MPSC issued an order approving the RCP, with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility on the basis of natural gas market prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced natural gas consumed by the MCV Facility will benefit our ownership interest in the MCV Partnership.
The substantial MCV Facility fuel cost savings will be used first to offset fully the cost of replacement power. Second, $5 million annually will be used to fund a renewable energy program. Remaining savings will be split between the MCV Partnership and Consumers. Consumers' direct savings will be shared 50 percent with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct savings from the RCP, after a portion is allocated to customers, will be used to offset our capacity and fixed energy underrecoveries expense. Since the MPSC has excluded these underrecoveries from the rate making process, we anticipate that our savings from the RCP will not affect our return on equity used in our base rate filings.
In January 2005, Consumers and the MCV Partnership's general partners accepted the terms of the order and implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed an application for rehearing of the MPSC order. The Attorney General also filed a claim of appeal with the Michigan Court of Appeals. We cannot predict the outcome of these appeals.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal issued its decision in the MCV Partnership's tax appeal against the City of Midland for tax years 1997 through 2000. The MCV Partnership estimates that the decision will result in a refund to the MCV Partnership of approximately $35 million in taxes plus $10 million of interest. The Michigan Tax Tribunal decision has been appealed to the Michigan Court of Appeals by the City of Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a pending case with the Michigan Tax Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the outcome of these proceedings; therefore,
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the above refund (net of approximately $16 million of deferred expenses) has not been recognized in 2004 earnings.
NUCLEAR PLANT DECOMMISSIONING: Decommissioning funding practices approved by the MPSC require us to file a report on the adequacy of funds for decommissioning at three-year intervals. We prepared and filed updated cost estimates for Big Rock and Palisades on March 31, 2004. Excluding additional costs for spent nuclear fuel storage, due to the DOE's failure to accept this spent nuclear fuel on schedule, these reports show a decommissioning cost of $361 million for Big Rock and $868 million for Palisades. Since Big Rock is currently in the process of being decommissioned, the estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars.
In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding the decommissioning trust funds for both sites. In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. The MPSC order set the annual decommissioning surcharge for Palisades at $6 million through 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability and asset retirement obligation.
Big Rock: Excluding the additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we are currently projecting that the level of funds provided by the trust for Big Rock will fall short of the amount needed to complete the decommissioning by $26 million. At this time, we plan to provide the additional amounts needed from our corporate funds and, subsequent to the completion of radiological decommissioning work, seek recovery of such expenditures at the MPSC. We cannot predict how the MPSC will rule on our request. The following table shows our Big Rock decommissioning activities:
- -------------------------
(a) Includes site restoration expenditures.
These activities had no material impact on net income. At December 31, 2004, we have an investment in nuclear decommissioning trust funds of $52 million for Big Rock. In addition, at December 31, 2004, we have charged $8 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.
Palisades: Excluding additional nuclear fuel storage costs due to the DOE's failure to accept this spent fuel on schedule, we concluded that the existing surcharge for Palisades needed to be increased to $25 million annually, beginning January 1, 2006, and continue through 2011, our current license expiration date. In June 2004, we filed an application with the MPSC seeking approval to increase the surcharge for recovery of decommissioning costs related to Palisades beginning in 2006. In September 2004, we announced that we will seek a 20-year license renewal for Palisades. In January 2005, we filed a settlement agreement with the MPSC that was agreed to by four of the six parties. The settlement agreement provides for the continuation of the existing $6 million annual decommissioning surcharge through 2011 and for the next periodic review to be filed in March 2007. We are seeking MPSC approval of the settlement, under a contested settlement proceeding, but cannot predict the outcome.
At December 31, 2004, we have an investment in the MPSC nuclear decommissioning trust funds of $513 million for Palisades. In addition, at December 31, 2004, 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 6, Asset Retirement Obligations.
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NUCLEAR MATTERS:
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other utilities participated, has not been successful in producing more specific relief for the DOE's failure to accept the spent nuclear fuel.
There are two court decisions that support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. Over 60 utilities have initiated litigation in the United States Court of Claims; we filed our complaint in December 2002. In July 2004, the DOE filed an amended answer and motion to dismiss the complaint. In October 2004, we filed a response to the DOE's motion and our motion for summary judgment on liability. Oral argument has been held, and the motions are now before the Court for a decision. If our litigation against the DOE is successful, we anticipate future recoveries from the DOE. We plan to use recoveries to pay the cost of spent nuclear fuel storage until the DOE takes possession as required by law. We can make no assurance that the litigation against the DOE will be successful.
In July 2002, Congress approved and the President signed a bill designating the site at Yucca Mountain, Nevada, for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE will submit an application to the NRC sometime in 2005 for a license to begin construction of the repository. The application and review process is estimated to take several years.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $27 million in any policy year if insured losses in excess of NEIL's maximum policyholders surplus occur at our, or any other member's, nuclear facility. NEIL's policies include coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. The United States Congress enacted the Price-Anderson Act to provide financial liability protection for those parties who may be liable for a nuclear accident or incident. Part of the Price-Anderson Act's financial protection is a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed if a nuclear incident occurs at any nuclear generating facility. The maximum assessment against us could be $101 million per occurrence, limited to maximum annual installment payments of $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.
GAS CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. We have completed initial investigations at the CE-55
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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. We base the estimates on discounted 2003 costs using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through insurance proceeds and MPSC-approved rates. As of December 31, 2004, we have recorded a liability of $38 million, net of $44 million of expenditures incurred to date, and a regulatory asset of $65 million. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs.
In its November 2002 gas distribution rate order, the MPSC authorized us to continue to recover approximately $1 million of manufactured gas plant facilities environmental clean-up costs annually. This amount will continue to be offset by $2 million to reflect amounts recovered from all other sources. We defer and amortize, over a period of 10 years, manufactured gas plant facilities environmental clean-up costs above the amount currently included in rates. Additional amortization of the expense in our rates cannot begin until after a prudency review in a gas rate case.
GAS RATE MATTERS
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs for prudency in an annual reconciliation proceeding.
The following table summarizes our GCR reconciliation filings with the MPSC. Additional details related to these proceedings follow the table.
Gas Cost Recovery Reconciliation
Net over-recovery amounts included in the table above include refunds that we received from our suppliers which are required to be refunded to our customers.
GCR Year 2003-2004: In February 2005, the MPSC approved a settlement agreement that resulted in a credit to our GCR customers for a $28 million over-recovery, plus $3 million interest, using a roll-in refund methodology. The roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan year.
GCR Plan for Year 2004-2005: In December 2003, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2004 through March 2005. In June 2004, the MPSC issued a final
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Order in our GCR plan approving a settlement. The settlement included a quarterly mechanism for setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
GCR Plan for Year 2005-2006: In December 2004, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2005 through March 2006. Our request proposes using a GCR factor consisting of:
- a base GCR factor of $6.98 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future events.
The GCR factor can be adjusted monthly, provided it remains at or below the current ceiling price. The quarterly adjustment mechanism allows an increase in the GCR ceiling price to reflect a portion of cost increases if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. Actual gas costs and revenues will be subject to an annual reconciliation proceeding.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a gas rate increase in the annual amount of $156 million. In December 2003, the MPSC granted an interim rate increase in the amount of $19 million annually. The MPSC also ordered an annual $34 million reduction in our annual depreciation expense and related taxes.
On October 14, 2004, the MPSC issued its Opinion and Order on final rate relief. In the order, the MPSC authorized us to place into effect surcharges that would increase annual gas revenues by $58 million. Further, the MPSC rescinded the $19 million annual interim rate increase. The final rate relief was contingent upon our agreement to:
- achieve a common equity level of at least $2.3 billion by year-end 2005 and propose a plan to improve the common equity level thereafter until our target capital structure is reached,
- make certain safety-related operation and maintenance, pension, retiree health-care, employee health-care, and storage working capital expenditures for which the surcharge is granted,
- refund surcharge revenues when our rate of return on common equity exceeds its authorized 11.4 percent rate,
- prepare and file annual reports that address certain issues identified in the order, and
- file a general rate case on or before the date that the surcharge expires (which is two years after the surcharge goes into effect).
On October 15, 2004, we agreed to these commitments.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas utility plant depreciation case originally filed in June 2001. On December 18, 2003, the MPSC ordered an annual $34 million reduction in our depreciation expense and related taxes in an interim rate order issued in our 2003 gas rate case.
In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case. The October 2004 order requires us to file an application for new depreciation accrual rates for our natural gas utility plant on, or no earlier than three months prior to, the date we file our next natural gas general rate case. The MPSC also directed us to undertake a study to determine why our removal costs are in excess of those of other regulated Michigan natural gas utilities and file a report with the MPSC Staff on or before December 31, 2005.
In February 2005, we requested a delay in the filing date for the next depreciation case until after the MPSC considers the removal cost study, and after the MPSC issues an order in a pending case relating to asset retirement obligation accounting.
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OTHER MATTERS
COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees are represented by the Utility Workers of America Union. The Union represents Consumers' operating, maintenance, and construction employees and our call center employees. The collective bargaining agreement with the Union for our operating, maintenance, and construction employees will expire on June 1, 2005 and negotiations for a new agreement is underway currently. The collective bargaining agreement with the Union for our call center employees will expire on August 1, 2005.
OTHER CONTINGENCIES
In addition to the matters disclosed within this Note, we are party to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or results of operations.
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3: FINANCINGS AND CAPITALIZATION
Long-term debt as of December 31 follows:
- ------------------------- (a) Represents the weighted average interest rate at December 31, 2004 (5.097 percent at December 31, 2003).
(b) We consolidate the FMLP in accordance with Revised FASB Interpretation No. 46. The FMLP debt is essentially project debt secured by certain assets of the MCV Partnership and the FMLP. The debt is non-recourse to other assets of Consumers.
(c) Maturity date uncertain.
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FINANCINGS: The following is a summary of significant long-term debt issuances and retirements during 2004:
Issuance costs associated with the issuances of FMBs totaled $7 million and are being amortized ratably over the lives of the related debt. Call premiums associated with the debt retirements totaled $20 million and are being amortized ratably over the lives of the newly issued debt.
SUBSEQUENT FINANCING ACTIVITIES: In January 2005, we issued $250 million of 5.15 percent FMBs due 2017. We used the net proceeds of $247 million to pay off our $60 million long-term bank loan, to redeem our $73 million 8.36 percent subordinated deferrable interest notes, and to redeem our $124 million 8.20 percent subordinated deferrable interest notes. The subordinated deferrable interest notes are classified as Long-term debt -- related parties on our accompanying Consolidated Balance Sheets.
FIRST MORTGAGE BONDS: We secure our FMBs 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.
SECURITIZATION BONDS: Securitization bonds are collateralized by certain regulatory assets. The bondholders have no recourse to our other assets. Through our rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses on the Securitization bonds. Securitization surcharges totaled $50 million annually in 2003 and 2004.
LONG-TERM DEBT -- RELATED PARTIES: We formed various statutory wholly-owned business trusts for the sole purpose of issuing preferred securities and lending the gross proceeds to ourselves. The sole assets of the trusts consist of the debentures described below. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trusts issued. We determined that we do not hold the controlling financial interest in our trust preferred security structures. Accordingly, those entities were deconsolidated as of December 31, 2003 and are reflected in Long-term debt -- related parties. The trust preferred securities were previously included in mezzanine equity.
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The following is a summary of Long-term debt -- related parties as of December 31:
- ------------------------- (a) Redeemed in February 2005.
(b) Redeemed in January 2005 with available cash.
In the event of default, holders of the trust preferred securities would be entitled to exercise and enforce the trusts' creditor rights against us, which may include acceleration of the principal amount due on the debentures. 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.
DEBT MATURITIES: At December 31, 2004, the aggregate annual maturities for long-term debt for the next five years are:
REGULATORY AUTHORIZATION FOR FINANCINGS: We have FERC authorization to issue or guarantee up to $1.1 billion of short-term securities and up to $1.1 billion of short-term FMBs as collateral for such short-term securities. We have FERC authorization to issue up to $1 billion of long-term securities for refinancing or refunding purposes, $1.5 billion of long-term securities for general corporate purposes, and $2.5 billion of long-term FMBs to be issued solely as collateral for other long-term securities.
REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities with banks are available as of December 31, 2004:
- ------------------------- (a) This facility expires in August 2005 and may be extended annually at Consumers' option to July 31, 2007. The interest rate on borrowings under this facility is LIBOR plus 125 basis points. Annual fees for letters-of-
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credit are 125 basis points on the amount outstanding. A quarterly fee of 22.5 basis points is payable on the average daily unused balance.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we currently sell certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. We sold $304 million of receivables at December 31, 2004 and we sold $297 million of receivables at December 31, 2003. These sold amounts are excluded from accounts receivable on our Consolidated Balance Sheets. We continue to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against our other assets for failure of a debtor to pay when due and the purchaser has no right to any receivables not sold. No gain or loss has been recorded on the receivables sold and we retain no interest in the receivables sold.
Certain cash flows under our accounts receivable sales program are shown in the following table:
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at December 31, 2004, we had $456 million of unrestricted retained earnings available to pay common stock dividends. However, covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. In October 2004, the MPSC rescinded its December 2003 interim gas rate order, which included a $190 million annual dividend cap. For the year ended December 31, 2004, we paid $190 million in common stock dividends to CMS Energy.
PREFERRED STOCK: Our Preferred Stock outstanding follows:
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 inception 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 table describes our guarantees at December 31, 2004:
- ------------------------- (a) Recourse provision indicates the approximate recovery from third parties including assets held as collateral.
The following table provides additional information regarding our guarantees:
4: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments or other valuation techniques.
The cost and fair value of our long-term financial instruments are as follows:
- ------------------------- (a) Includes current maturities of $118 million at December 31, 2004 and $28 million at December 31, 2003. Settlement of long-term debt is generally not expected until maturity.
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(b) Includes current maturities of $180 million at December 31, 2004.
(c) At December 31, 2004, we held 2.4 million shares of CMS Energy Common Stock.
(d) Nuclear decommissioning investments include cash and equivalents and accrued income totaling $11 million at December 31, 2004 and $11 million at December 31, 2003. Unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities.
(e) The fair value of available-for-sale debt securities by contractual maturity as of December 31, 2004 is as follows:
Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $139 million as of December 31, 2004. These securities represent funds restricted primarily for future lease payments and are classified as Other assets on our Consolidated Balance Sheets. These investments have original maturity dates of approximately one year or less and, because of their short maturities, their carrying amounts approximate their fair values.
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, and equity security prices. We manage these risks using established policies and procedures, under the direction of both an executive oversight committee consisting of senior management representatives and a risk committee consisting of business-unit managers. We may use various contracts to manage these risks including swaps, options, futures, and forward contracts.
We intend that any gains or losses on these contracts will be offset by an opposite movement in the value of the item at risk. We enter into all risk management contracts for purposes other than trading. These contracts contain credit risk if the counterparties, including financial institutions and energy marketers, fail to perform under the agreements. We minimize such risk through established credit policies that include performing financial credit reviews of 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 and our current exposures, we do not anticipate a material adverse effect on our financial position or earnings as a result of counterparty nonperformance.
Contracts used to manage market risks 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 is then adjusted quarterly to reflect any change in the market value of the contract, a practice known as marking the contract to market. Changes in fair value (that is, gains or losses) are reported either in earnings or accumulated other comprehensive income, depending on whether the derivative qualifies for cash flow hedge accounting treatment.
For derivative instruments to qualify for hedge accounting, 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 recognized immediately in earnings. If a
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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. The ineffective portion, if any, of all hedges is recognized in earnings.
We use a combination of quoted market prices, prices obtained from external sources, such as brokers, and mathematical valuation models to determine the fair value of those contracts requiring derivative accounting. 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. In connection with the market valuation of our derivative contracts, we maintain reserves, if necessary, for credit risks based on the financial condition of counterparties.
The majority of our contracts are not subject to derivative accounting under SFAS No. 133 because they qualify for the normal purchases and sales exception, or because there is not an active market for the commodity. Our electric capacity and energy contracts are not accounted for as derivatives due to the lack of an active energy market in the state of Michigan and the significant transportation costs that would be incurred to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio. Similarly, our coal purchase contracts are not accounted for as derivatives due to the lack of an active market for the coal that we purchase. If active markets for these commodities develop in the future, we may be required to account for these contracts as derivatives, and the resulting mark-to-market impact on earnings could be material to our financial statements.
The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005, which will include day-ahead and real-time energy market information and centralized dispatch for market participants. At this time, we believe that the commencement of this market will not constitute the development of an active energy market in the state of Michigan. However, after having adequate experience with the Midwest Energy Market, we will reevaluate whether or not the activity level within this market leads to the conclusion that an active energy market exists.
Derivative accounting is required for certain contracts used to limit our exposure to commodity price risk. The following table reflects the fair value of all contracts requiring derivative accounting:
- ------------------------- (a) The amount associated with derivative contracts held by the MCV Partnership as of December 31, 2003 represents our proportionate share of the unrealized gain on those contracts accounted for as cash flow hedges included in Accumulated other comprehensive income. Our proportionate share of the total fair value of all derivative instruments held by the MCV Partnership as of December 31, 2003 was $51 million, and is included in Investments -- Midland Cogeneration Venture Limited Partnership on our Consolidated Balance Sheets.
The fair value of our derivative contracts is included in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets.
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GAS CONTRACTS: Our gas utility business uses fixed-priced weather-based gas supply call options and fixed-priced gas supply call and put options to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. Unrealized gains and losses associated with these options are reported directly in earnings as part of Other income, and then directly offset in earnings and recorded on the balance sheet as a regulatory asset or liability as part of the GCR process. At December 31, 2004, we held fixed-priced weather- based gas supply call options and had sold fixed-priced gas supply put options.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV PARTNERSHIP:
Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership believes that certain of its long-term natural gas contracts qualify as normal purchases under SFAS No. 133, and therefore, these contracts were not recognized at fair value on the balance sheet as of December 31, 2004. The MCV Partnership also held certain long-term gas contracts that did not qualify as normal purchases as of December 31, 2004, because these contracts contained volume optionality. Accordingly, these contracts were accounted for as derivatives, with changes in fair value recorded in earnings each quarter. The MCV Partnership expects future earnings volatility on these contracts, since gains and losses will be recorded each quarter. For the year ended December 31, 2004, we recorded a $19 million net loss associated with these gas contracts in Fuel for electric generation on our Consolidated Statements of Income. The fair value of these contracts will reverse over the remaining life of the contracts ranging from 2005 to 2007.
Due to the implementation of the RCP in January 2005, the MCV Partnership has determined that a significant portion of its gas fuel contracts no longer qualify as normal purchases because the contracted gas will not be consumed for electric production. Accordingly, these contracts will be treated as derivatives and will be marked-to-market through earnings each quarter, which could increase earnings volatility. Based on market prices for natural gas as of January 31, 2005, the accounting for the MCV Partnership's long-term gas contracts, including those affected by the implementation of the RCP, could result in an estimated $100 million (pretax before minority interest) gain recorded to earnings in the first quarter of 2005. This estimated gain will reverse in subsequent quarters as the contracts settle. For further details on the RCP, see Note 2, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture." If there are further changes in the level of planned electric production or gas consumption, the MCV Partnership may be required to account for additional long-term gas contracts as derivatives, which could add to earnings volatility.
Gas Fuel Futures and Swaps: The MCV Partnership enters into natural gas futures contracts, option contracts, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage, and transportation arrangements. At December 31, 2004, the MCV Partnership held gas fuel futures and swaps.
The contracts that are used to secure anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133. The MCV Partnership also engages in cost mitigation activities to offset the fixed charges the MCV Partnership incurs in operating the MCV Facility. These cost mitigation activities include the use of futures and options contracts to purchase and/or sell natural gas to maximize the use of the transportation and storage contracts when it is determined that they will not be needed for the MCV Facility operation. Although these cost mitigation activities do serve to offset the fixed monthly charges, these cost mitigation activities are not considered a normal course of business for the MCV Partnership and do not qualify as hedges. Therefore, the mark-to-market gains and losses from these cost mitigation activities are recorded in earnings each quarter.
As of December 31, 2004, we have recorded a cumulative net gain of $21 million, net of tax, in Accumulated other comprehensive income relating to our proportionate share of the contracts held by the MCV
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Partnership that qualify as cash flow hedges. This balance represents natural gas futures, options, and swaps with maturities ranging from January 2005 to December 2009, of which $11 million of this gain is expected to be reclassified as an increase to earnings during the next 12 months. In addition, for the year ended December 31, 2004, we recorded a net gain of $37 million in earnings from hedging activities related to natural gas requirements for the MCV Facility operations and a net gain of $2 million in earnings from the MCV Partnership's cost mitigation activities.
5: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after June 30, 2003,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) plan,
- benefits to a select group of management under EISP, and
- health care and life insurance benefits under OPEB.
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.
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) in 2003 as a result of the increase in the additional minimum pension liability. As a result of company contributions in 2003, 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 $30 million at December 31, 2004, and $22 million at December 31, 2003. The assets are classified as Other non-current assets. The Accumulated Benefit Obligation for SERP was $30 million at December 31, 2004 and $19 million at December 31, 2003.
401(k): Employer matching contributions to the 401(k) plan are invested in CMS Energy common stock. The amount charged to expense for this plan was $8 million in 2002. The employer's match for the 401(k) plan was suspended on September 1, 2002 and was resumed on January 1, 2005.
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The MCV Partnership sponsors a defined contribution retirement plan covering all employees. Under the terms of the plan, the MCV Partnership makes contributions of either 5 or 10 percent of an employee's eligible annual compensation dependent upon the employee's age. The MCV Partnership also sponsors a 401(k) savings plan for employees. Contributions and costs for this plan are based on matching an employee's savings up to a maximum level. Amounts contributed under these plans were $1 million in 2004.
EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of 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, 2004, the Accumulated Benefit Obligation of the EISP was $4 million.
OPEB: Retiree health care costs at December 31, 2004 are based on the assumption that costs would increase 7.5 percent in 2004. The rate of increase is expected to be 10 percent for 2005. The rate of increase is expected to slow to an estimated 5 percent by 2010 and thereafter.
The MCV Partnership sponsors defined cost postretirement health care plans that cover all full-time employees, except key management. Participants in the postretirement health care plans become eligible for the benefits if they retire on or after the attainment of age 65 or upon a qualified disability retirement, or if they have 10 or more years of service and retire at age 55 or older. The accumulated benefit obligation of the MCV Partnership's postretirement plans was $5 million at December 31, 2004. The MCV Partnership's net periodic postretirement health care cost for 2004 was less than $1 million.
The health care cost trend rate assumption affects the estimated costs recorded. A one-percentage point change in the assumed health care cost trend assumption would have the following effects:
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.
The measurement date for all of Consumers' plans is November 30 for 2004, and December 31 for 2003 and 2002. We believe accelerating the measurement date on our benefit plans by one month is preferable as it improves control procedures and allows more time to review the completeness and accuracy of the actuarial measurements. As a result of the measurement date change in 2004, we recorded a $1 million cumulative effect of change in accounting, net of tax benefit, as a decrease to earnings. We also increased the amount of accrued benefit cost on our Consolidated Balance Sheets by $2 million. The effect of the measurement date change was immaterial. The measurement date for the MCV Partnership's plan is December 31, 2004.
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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 expert opinions of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed periodically for reasonability and appropriateness.
Costs: The following table recaps the costs incurred in our retirement benefits plans:
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Reconciliations: The following table reconciles the funding of our retirement benefits plans with our retirement benefits plans' liability:
- ------------------------- (a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy, which is tax-exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have incorporated, retroactively, the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $148 million. The remeasurement resulted in a reduction of OPEB cost of $23 million for 2004. The reduction of $23 million includes $7 million in capitalized OPEB costs. For additional details, see Note 13, Implementation of New Accounting Standards.
(b) The Pension Plan's Accumulated Benefit Obligation of $1.082 billion exceeded the value of the Pension Plan assets and net balance sheet asset at December 31, 2004. As a result, we recorded an additional minimum liability of $419 million. Consistent with MPSC guidance, Consumers recognized the cost of their additional minimum liability as a regulatory asset. Accordingly, Consumers' additional minimum liability includes an intangible asset of $21 million, and a regulatory asset of $372 million. The Accumulated Benefit Obligation for the Pension Plan was $1.019 billion at December 31, 2003.
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Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
- ------------------------- (a) At November 30, 2004, there were 4,892,000 shares of CMS Energy Common Stock in the Pension Plan assets with a fair value of $50 million, and 493,000 shares in the OPEB plan assets, with a fair value of $5 million. 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.
(b) The percentage of fixed income at December 31, 2003 is high because our December contribution of $329 million was deposited temporarily into fixed income securities.
We contributed $62 million to our OPEB plan in 2004. We plan to contribute $62 million to our OPEB plan in 2005. We did not contribute to our Pension Plan in 2004. We do not plan to contribute to our Pension Plan in 2005.
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 a Standard & Poor's 500 Index fund. The fixed income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.
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Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:
- ------------------------- (a) OPEB benefit payments are net of employee contributions and expected Medicare Part D subsidy payments.
6: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: This standard became effective January 2003. It requires companies to record the fair value of the cost to remove assets at the end of their useful life, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. As required by SFAS No. 71, we accounted for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would increase by $22 million.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, gas transmission and electric and gas distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock are based on decommissioning studies that largely utilize third-party cost estimates.
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The following tables describe our assets that have legal obligations to be removed at the end of their useful life:
The Palisades and Big Rock cash flow revisions resulted from new decommissioning reports filed with the MPSC in March 2004. The Palisades ARO also reflects a cash flow revision for the probability of operating license renewal; the renewal would extend the plant's operating license by twenty years. For additional details, see Note 2, Contingencies, "Other Electric Contingencies -- Nuclear Plant Decommissioning."
On October 14, 2004 the MPSC issued a generic proceeding to review SFAS No. 143, Accounting for Asset Retirement Obligations, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and their accounting and ratemaking issues. Utilities are required to respond to the Order by March 15, 2005. We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities; we anticipate no financial impact.
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7: 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 $4 million in 2004 and $46 million in 2003.
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, 2004, we had AMT credit carryforwards in the amount of $20 million that do not expire, and tax loss carryforwards in the amount of $69 million that expire in 2021 through 2023. In addition, at December 31, 2004, we had charitable contribution carryforwards in the amount of $13 million that expire in 2005 through 2008 and general business credit carryforwards in the amount of $4 million that primarily expire in 2005, for which a valuation allowance has been provided.
The significant components of income tax expense (benefit) consisted of:
The principal components of our deferred tax assets (liabilities) recognized in the balance sheet are as follows:
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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:
8: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee Directors or consultants based on their contributions to the successful management of the company. On May 28, 2004, shareholders approved an amendment to the Plan, with an effective date of June 1, 2004. The amendment established a 5-year term for the Plan. The Plan includes the following type of awards:
- phantom shares,
- performance units,
- restricted stock,
- stock options,
- stock appreciation rights, and
- management stock purchases.
Phantom shares are valued at the fair market price of common stock when granted. They give the holder the right to receive the appreciation value of common stock on one or more valuation dates, according to a specified vesting schedule determined at time of grant. These shares are subject to forfeiture if employment terminates before vesting.
Performance units have an initial value established at the time of grant. Performance criteria are established at the time of grant and, depending upon the extent to which they are met, will determine the value of the payout, which may be in the form of cash, common stock, or a combination of both. These units are subject to forfeiture if employment terminates.
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Restricted shares of common stock are outstanding shares with full voting and dividend rights. These awards vest 100 percent after three years and are subject to achievement of specified levels of total shareholder return including a comparison to a peer group of companies. Some awards vest based solely on continued employment. These awards 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, defined as the excess of the market price of the stock at the date of exercise over the grant date price. All stock options and stock appreciation rights are valued at fair market price when granted. All options and rights may be exercised upon grant, and expire up to 10 years and one month from the date of grant.
Management stock purchases are the election of select participants in the Officer's Incentive Compensation Plan to receive all or a portion of their incentive payments in the form of shares of restricted common stock or shares of restricted stock units. These participants may also receive awards of additional restricted common stock or restricted stock units provided the total value of these additional grants does not exceed $2.5 million for any fiscal year.
Under the revised Plan, shares awarded or subject to options, phantom shares and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such grants or awards to any participant exceed 250,000 shares in any fiscal year.
Shares for which payment or exercise is in cash, as well as shares or options that are forfeited, may be awarded or granted again under the Plan.
Awards of up to 5,482,690 shares of CMS Energy Common Stock may be issued as of December 31, 2004. All grants awarded under this Plan in 2004 were in the form of restricted stock.
The following table summarizes the restricted stock and stock options granted to our key employees under the Performance Incentive Stock Plan:
At December 31, 2004, 316,312 of the 863,202 shares of CMS Energy restricted common stock outstanding are subject to performance objectives. Compensation expense for restricted stock was $2 million in 2004, $4 million in 2003, and less than $1 million in 2002.
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The following table summarizes our stock options outstanding at December 31, 2004:
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) There were no stock option grants during 2004.
(b) For 2002, there were two stock option grants totaling 490,600 options.
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) There were no stock option grants during 2004.
(b) For 2002, there were two stock option grants totaling 490,600 options.
We recorded $3 million as stock-based employee compensation cost for 2003, and $1 million for 2002. All stock options vest at date of grant.
9: 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 fair value, or
- renew the lease at fair rental value.
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Our capital leases are comprised mainly of leased service vehicles and office furniture. As of December 31, 2004, capital lease obligations totaled $58 million. 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. Capital lease expenses were $13 million in 2004, $17 million in 2003, and $20 million in 2002. In November 2003, we exercised our purchase option under the capital lease agreement for our main headquarters building in Jackson, Michigan. Operating lease charges were $13 million in 2004, $13 million in 2003, and $13 million in 2002.
In order to obtain permanent financing for the MCV Facility, the MCV Partnership entered into a sale and lease back agreement with a lessor group, which includes the FMLP, for substantially all of the MCV Partnership's fixed assets. In accordance with SFAS No. 98, the MCV Partnership accounts for the transaction as a financing arrangement. As of December 31, 2004, finance lease obligations totaled $286 million, which represents the third-party portion of the MCV Partnership's finance lease obligation. Charges under the MCV Partnership's finance lease obligation were $105 million in 2004. For additional details on transactions with the MCV Partnership and the FMLP, see Note 2, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
Minimum annual rental commitments under our non-cancelable leases at December 31, 2004 were:
10: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the MCV Partnership. We consolidated their assets, liabilities, and financial activities into our financial statements as of and for the year ended December 31, 2004. As of December 31, 2004, the MCV Partnership had total assets of $1.980 billion and a net loss of $24 million for the year. For 2003 and 2002, the MCV Partnership was accounted for as an equity method investment and their summarized financial information is shown below. Our 49 percent investment in the MCV Partnership was $419 million at December 31, 2003 and our share of net income was $29 million for the year ended December 31, 2003 and $65 million for the year ended December 31, 2002.
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Under the PPA with the MCV Partnership discussed in Note 2, Contingencies, 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 for 2003 and 2002 follows:
STATEMENTS OF INCOME
BALANCE SHEET
- ------------------------- (a) Revenue from Consumers totaled $514 million in 2003 and $557 million in 2002.
(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.
(d) The 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 the FMLP. The MCV Partnership's lease obligations, assets, and operating revenues secure the FMLP's debt. The following table summarizes obligation and payment information regarding the direct finance lease:
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(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.
11: 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:
12: REPORTABLE SEGMENTS
Our reportable segments are strategic business units organized and managed by the nature of the products and services each provides. We evaluate performance based upon the net income of each segment. 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 expense, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue. Pension provisions are allocated based on labor dollars.
We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income available to common stockholder by segment. The "Other" segment includes our consolidated special purpose entity for the sale of trade receivables, the MCV Partnership and the FMLP.
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The following table shows our financial information by reportable segment:
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- ------------------------- (a) 2002 excludes $28 million benefit due to the change in accounting for derivative instruments.
(b) 2002 excludes $10 million tax expense 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 our 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.
(e) Amounts include electric restructuring implementation plan, 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.
13: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The FASB issued this Interpretation in January 2003. The objective of the Interpretation is to assist in determining when one party controls another entity in circumstances where a controlling financial interest cannot be properly identified based on voting interests. Entities with this characteristic are considered variable interest entities. The Interpretation requires the party with the controlling financial interest, known as the primary beneficiary, in a variable interest entity to consolidate the entity.
In December 2003, the FASB issued Revised FASB Interpretation No. 46. For entities that had not previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No. 46 provided an implementation deferral until the first quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation No. 46 for all entities.
We determined that we are the primary beneficiary of both the MCV Partnership and the FMLP. We have a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is the primary purchaser of power from the MCV Partnership through a long-term power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the MCV Facility, which results in Consumers holding a 35 percent lessor interest in the MCV Facility. Collectively, these interests make us the primary beneficiary of these entities. As such, we consolidated their assets, liabilities, and activities into our financial statements as of and for the year ended December 31, 2004. These partnerships have third-party obligations totaling $582 million at December 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $1.426 billion at December 31, 2004. The creditors of these partnerships do not have recourse to the general credit of Consumers.
We determined that we are not the primary beneficiary of our trust preferred security structures. Accordingly, those entities were deconsolidated as of December 31, 2003. Company Obligated Trust Preferred Securities totaling $490 million that were previously included in mezzanine equity, were eliminated due to deconsolidation. At December 31, 2004, we reflected Long-term debt -- related parties of $326 million, current portion of Long-term debt -- related parties of $180 million, and an investment in related parties of $16 million.
We are not required to restate prior periods for the impact of this accounting change.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law in December 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is exempt from federal taxation, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D.
We believe our plan is actuarially equivalent to Medicare Part D and have incorporated retroactively the effects of the subsidy into our financial statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation as of December 31, 2003 to incorporate the impact of the Act, which resulted in a reduction to the accumulated postretirement benefit obligation of $148 million. The remeasurement resulted in a total OPEB cost reduction of $23 million for 2004. Consumers capitalizes a portion of OPEB cost in accordance with regulatory accounting. As such, the remeasurement resulted in a net reduction of OPEB expense of $16 million for 2004.
EITF ISSUE NO. 03-1, THE MEANING OF OTHER-THAN-TEMPORARY IMPAIRMENTS: The Issue addresses the definition of an other-than-temporary impairment of certain investments and provides additional disclosure requirements. The scope of EITF Issue No. 03-1 includes debt and equity securities accounted for under SFAS No. 115, debt and equity securities held by non-profit organizations under SFAS No. 124, and cost method investments under APB No. 18. We analyzed our in-scope investments under the guidance of this Issue and have provided additional disclosures.
FSP 109-1, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE TAX DEDUCTION PROVIDED TO U.S. BASED MANUFACTURERS BY THE AMERICAN JOBS CREATION ACT OF 2004: The American Jobs Creation Act of 2004 provides for a deduction, starting in 2005, of a portion of the income from certain production activities, including the production of electricity. FSP 109-1 indicates that the deduction should be accounted for as a special deduction rather than a tax rate reduction under SFAS No. 109. We are currently studying this act for its impact on us; however, we do not anticipate a material amount of tax benefit from the domestic production activities deduction in the near future.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to expense the grant date fair value of employee stock options and similar awards. The Statement also clarifies and expands SFAS No. 123's guidance in several areas, including measuring fair value, classifying an award as equity or as a liability, and attributing compensation cost to reporting periods.
In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to require that excess tax benefits related to the excess of the tax deductible amount over the compensation cost recognized be classified as a financing cash inflow rather than as a reduction of taxes paid in operating activities.
This Statement is effective for us as of the beginning of third quarter 2005. We adopted the fair value method of accounting for share-based awards effective December 2002, and therefore, expect this statement to have an insignificant impact on our results of operations when it becomes effective.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
14: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
- ------------------------- (a) As of March 31, 2004, we determined that the MCV Partnership and the FMLP should be consolidated in accordance with revised FASB Interpretation No. 46. As such, we consolidated their financial activities into our financial statements as of and for the year ended December 31, 2004. For additional details, see Note 13, Implementation of New Accounting Standards.
(b) Net of tax.
(c) Quarterly data for March 31, 2004 differs from amounts previously reported as a result of accelerating the measurement date on our benefit plans by one month. For additional information, see Note 5, Retirement Benefits.
(d) Quarterly data for March 31, 2004 differs from amounts previously reported due to the remeasurement of our post retirement benefit obligation in accordance with FASB Staff Position, No. SFAS 106-2. For additional information, see Note 13, Implementation of New Accounting Standards.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder of Consumers Energy Company
We have audited the accompanying consolidated balance sheets of Consumers Energy Company (a Michigan corporation and wholly-owned subsidiary of CMS Energy Corporation) as of December 31, 2004 and 2003, 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, 2004. 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 49% owned variable interest entity which has been consolidated in 2004 pursuant to Revised Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities" and accounted for under the equity method of accounting in 2003 and 2002, have been audited by other auditors whose report has 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 report.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the 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, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 13 to the consolidated financial statements, in 2004, the Company adopted Revised Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities". In addition, as discussed in Note 5 to the consolidated financial statements, in 2004, the Company changed its measurement date for all Consumers Energy Company pension and postretirement benefit plans. As discussed in Notes 6 and 13 to the consolidated financial statements, in 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" and of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities".
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Consumers Energy Company's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2005 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Detroit, Michigan March 7, 2005
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of Midland Cogeneration Venture Limited Partnership:
We have completed an integrated audit of Midland Cogeneration Venture Limited Partnership's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
CONSOLIDATED FINANCIAL STATEMENTS
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows (not presented herein) present fairly, in all material respects, the financial position of Midland Cogeneration Limited Partnership (a Michigan limited partnership) and its subsidiaries (MCV) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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.
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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting, that MCV maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, MCV maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control -- Integrated Framework issued by COSO. MCV's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of MCV's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
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accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Detroit, Michigan February 25, 2005
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
CMS ENERGY
None.
CONSUMERS
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
CMS ENERGY
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES: Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on such evaluation, CMS Energy's CEO and CFO have concluded that its disclosure controls and procedures are effective as of the end of the period covered by this annual report.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: CMS Energy's management's assessment of internal control over financial reporting appears in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS, and is incorporated by reference herein.
CONSUMERS
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES: Under the supervision and with the participation of management, including its CEO and CFO, Consumers conducted an evaluation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on such evaluation, Consumers' CEO and CFO have concluded that its disclosure controls and procedures are effective as of the end of the period covered by this annual report.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: Consumers' management's assessment of internal control over financial reporting appears in ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS, and is incorporated by reference herein.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
CMS ENERGY
None.
CONSUMERS
None.
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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 principal accountant fees and services relating to Consumers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(1) Financial Statements and Reports of Independent Public Accountants for CMS Energy and Consumers are included in each company's ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA and are incorporated by reference herein.
(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) 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, 2004, 2003 AND 2002
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CONSUMERS ENERGY COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
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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 10th day of March 2005.
CMS ENERGY CORPORATION
By /s/ DAVID W. JOOS ------------------------------------ David W. Joos President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of CMS Energy Corporation and in the capacities and on the 10th day of March 2005.
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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 10th day of March 2005.
CONSUMERS ENERGY COMPANY
By /s/ DAVID W. JOOS ------------------------------------ David W. Joos Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of Consumers Energy Company and in the capacities and on the 10th day of March 2005.
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CMS ENERGY'S AND CONSUMERS' EXHIBIT INDEX