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 $6.288 billion in 2005, $5.472 billion in 2004 and $5.513 billion in 2003. CMS Energy operates in three business segments -- electric utility, gas utility, and enterprises. See BUSINESS SEGMENTS later in this Item 1 for further discussion of each segment.
CONSUMERS
Consumers was formed in Michigan in 1968 and is the successor to a corporation organized in Maine in 1910 that conducted business in Michigan from 1915 to 1968. Consumers serves companies operating in the automotive, metal, chemical and food products industries as well as a diversified group of other industries. In 2005, Consumers served 1.79 million electric customers and 1.71 million gas customers.
Consumers' consolidated operations account for a majority of CMS Energy's total assets and income, as well as a substantial portion of its operating revenue. Consumers' consolidated operating revenue was $5.232 billion in 2005, $4.711 billion in 2004 and $4.435 billion in 2003.
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 -- Electric Utility Properties, and -- Consumers Gas Utility -- Gas Utility Properties, below.
BUSINESS SEGMENTS
CMS ENERGY FINANCIAL INFORMATION
For further information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to all of CMS Energy's business segments and international and domestic operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION and CMS ENERGY'S CONSOLIDATED FINANCIAL STATEMENTS and NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSUMERS FINANCIAL INFORMATION
For further information with respect to operating revenue, net operating income, identifiable assets and liabilities attributable to Consumers' electric and gas utility operations, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- SELECTED FINANCIAL INFORMATION and CONSUMERS' CONSOLIDATED FINANCIAL STATEMENTS and NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSUMERS ELECTRIC UTILITY
ELECTRIC UTILITY OPERATIONS
Consumers' electric utility operating revenue was $2.701 billion in 2005, $2.586 billion in 2004 and $2.590 billion in 2003. Consumers' electric utility operations include the generation, purchase, distribution and sale of electricity. At year-end 2005, 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 2005, Consumers' electric sales were 39 billion kWh and retail open access deliveries were 4 billion kWh, for total electric deliveries of 43 billion kWh. 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.
Consumers' 2005 summer peak demand was 7,845 MW excluding retail open access loads and 8,474 MW including retail open access loads. For the 2004-05 winter period, Consumers' peak demand was 5,750 MW excluding retail open access loads and 6,385 MW including retail open access loads. In October 2005, Consumers experienced peak demand of 6,069 MW excluding retail open access loads and 6,644 MW including retail open access loads. Based on its summer 2005 forecast, Consumers carried an 11 percent reserve margin target. However, as a result of lower than forecasted peak loads, Consumers' ultimate reserve margin was 15 percent compared to 30 percent in 2004. Currently, Consumers owns or controls capacity necessary to supply approximately 101 percent of projected firm summer peak load for summer 2006 and is in the process of securing the additional capacity needed to meet its summer 2006 reserve margin target of 11 percent (111 percent of projected firm summer peak load). The ultimate use of the reserve margin will depend primarily on summer weather conditions, the level of retail open access requirements being served by others during the summer, and any unscheduled plant outages.
ELECTRIC UTILITY PROPERTIES
GENERATION: At December 31, 2005, Consumers' electric generating system consisted of the following:
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(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) Campbell A (13 MW) was on an extended forced outage and therefore has not been included in the total.
(f) Includes 1,240 MW of purchased contract capacity from the MCV Facility.
In 2005, through the Midwest Energy Market, long-term purchase contracts, options, spot market and other seasonal purchases, Consumers purchased up to 2,522 MW of net capacity from others, which amounted to 32 percent of Consumers' total system requirements.
DISTRIBUTION: Consumers' distribution system includes:
- 363 miles of high-voltage distribution radial lines operating at 120 kilovolts and above;
- 4,180 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;
- 55,373 miles of electric distribution overhead lines;
- 9,275 subsurface miles of underground distribution lines; and
- substations having an aggregate transformer capacity of 22,761,970 kilovoltamperes.
Consumers is interconnected to METC, a member of MISO. METC owns an interstate high voltage electric transmission system located in Michigan and is interconnected with neighboring utilities as well as out-state transmission systems.
FUEL SUPPLY: Consumers has four generating plant sites that burn coal. In 2005, these plants produced a combined total of 19,711 million kWhs of electricity, which represents 75 percent of Consumers' 26,347 million kWhs baseload supply, the capacity used to serve a constant level of customer demand. These plants burned 9.9 million tons of coal in 2005. On December 31, 2005, Consumers had on hand a 33-day supply of coal.
Consumers enters into a number of purchase obligations that represent normal business operating contracts. These contracts are used to assure an adequate supply of goods and services necessary to operate its business and to minimize exposure to market price fluctuations. Consumers believes that these future costs are prudent and reasonably assured of recovery in future rates.
Consumers has entered into coal supply contracts with various suppliers and associated rail transportation contracts for its coal-fired generating stations. Under the terms of these agreements, Consumers is obligated to take physical delivery of the coal and make payment based upon the contract terms. Consumers' coal supply contracts expire through 2010, and total an estimated $661 million. Its coal transportation contracts expire through 2009, and total an estimated $314 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.
At December 31, 2005, Consumers had future unrecognized commitments to purchase capacity and energy under long-term power purchase agreements with various generating plants. These contracts require monthly capacity payments based on the plants' availability or deliverability. These payments for 2006 through 2030 total an estimated $4.468 billion, to present value. This amount may vary depending upon plant availability and fuel costs. Consumers is obligated to pay capacity charges based only on the amount of capacity available at a given time, whether or not power is delivered to Consumers.
Consumers owns Palisades, an operating nuclear power plant located near South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers transferred its authority to operate Palisades to NMC. During 2005, Palisades' net generation was 6,636 million kWhs, constituting 25 percent of Consumers' baseload supply. Palisades' nuclear fuel supply responsibilities are under NMC's control as agent for Consumers. New fuel contracts are being written as NMC agreements. Consumers/NMC currently have sufficient contracts in place to supply 100 percent of the uranium concentrates and conversion services and 100 percent of the enrichment services requirements for the 2006 reload. A contract for uranium concentrates is in place to supply approximately 85 percent of the 2007 reload requirements. A contract for conversion services is in place to supply approximately 43 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.
In December 2005, Consumers announced plans to sell the Palisades nuclear plant and enter into a long-term power purchase agreement with the new owner. Consumers believes a sale is the best option for the company, as it will reduce risk and improve cash flow while retaining the benefits of the plant for customers. The Palisades sale will use a competitive bid process, providing interested companies the option to bid on the plant, as well as the related decommissioning liabilities and trust funds assets, and spent nuclear fuel at Palisades and Big Rock. Consumers expects to complete the sale in 2007.
As shown below, Consumers generates electricity principally from coal and nuclear fuel.
- ------------------------- (a) On June 20, 2001, the Palisades reactor was shut down so technicians could inspect a small steam leak on a control rod drive assembly. The defective components were replaced and the plant returned to service on January 21, 2002.
The cost of all fuels consumed, shown below, fluctuates with the mix of fuel burned.
- ------------------------- (a) Weighted average fuel costs.
The Nuclear Waste Policy Act of 1982 made the federal government responsible for the permanent disposal of spent nuclear fuel and high-level radioactive waste by 1998. The DOE has not arranged for storage facilities and it does not expect to receive spent nuclear fuel for storage in 2006. Palisades currently has spent nuclear fuel that exceeds its temporary on-site storage pool capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved steel and concrete vaults known as "dry casks." For additional information on disposal of nuclear fuel and Consumers' use of dry casks, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS.
CONSUMERS GAS UTILITY
GAS UTILITY OPERATIONS
Consumers' gas utility operating revenue was $2.483 billion in 2005, $2.081 billion in 2004 and $1.845 billion in 2003. Consumers' gas utility operations purchase, transport, store, distribute and sell natural gas. As of December 31, 2005, 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 2005, 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 355 bcf.
GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system consists of:
- 26,078 miles of distribution mains throughout Michigan's Lower Peninsula;
- 1,643 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 143 bcf.
GAS SUPPLY: In 2005, Consumers purchased 70 percent of the gas it delivered from United States producers and 24 percent from Canadian producers. Authorized suppliers in the gas customer choice program supplied the remaining 6 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, 2005, 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 and equity investments, is engaged in domestic and international diversified energy businesses including independent power production, electric distribution, and natural gas transmission, storage and processing. Enterprises' operating revenue was $1.110 billion in 2005, $808 million in 2004 and $1.085 billion in 2003.
NATURAL GAS TRANSMISSION
CMS Gas Transmission was formed in 1988 and owns, develops and manages domestic and international natural gas facilities. In 2005, CMS Gas Transmission's operating revenue was $18 million.
In June 2003, CMS Gas Transmission sold Panhandle to Southern Union Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union Panhandle Corp. purchased all of Panhandle's outstanding capital 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, 2005, CMS Gas Transmission had nominal processing capabilities of approximately 0.33 bcf per day of natural gas in Michigan.
At December 31, 2005, 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 2005, the independent power production business segment's operating revenue was $315 million.
INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2005, CMS Energy had ownership interests in operating independent power plants (excluding the MCV Facility) totaling 8,809 gross MW (4,308 net MW). In 2006, Enterprises plans to complete the restructuring of its operations by narrowing the scope of its existing operations and commitments to three regions: North America, 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 Energy's interest in independent power plants as of year-end 2005 (excluding the MCV Facility, discussed further below):
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(a) El Chocon sells its power primarily on a spot market basis; however, it has a high dispatch rate due to low cost. The El Chocon facility is held pursuant to a 30-year possession agreement. (b) Subject to obtaining adequate financing, the Takoradi Power Plant will be converted from single-cycle to combined-cycle with an increase in gross capacity from 224 MW to 341 MW. (c) The Jorf Lasfar facility is held pursuant to a right of possession agreement with the Moroccan state-owned Office National de l'Electricite. (d) SENECA is a combined generation/distribution utility that produces power for its sole use.
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 the 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 2005, CMS
ERM marketed approximately 57 bcf of natural gas and 3,842 GWh of electricity. Its operating revenue was $589 million in 2005, $381 million in 2004 and $711 million in 2003.
INTERNATIONAL ENERGY DISTRIBUTION
In October 2001, CMS Energy discontinued the operations of its international energy distribution business. In 2002, CMS Energy discontinued new development outside North America, which included closing all non-U.S. development offices. In 2003, due to the uncertainty of executing an asset sale on acceptable terms and conditions, CMS Energy reclassified SENECA, which is its energy distribution business in Venezuela, and CPEE, which is its energy distribution business in Brazil, to continuing operations.
CMS ENERGY AND CONSUMERS REGULATION
CMS Energy is a public utility holding company that was previously exempt from registration under PUHCA of 1935. PUHCA of 1935 was repealed by the Energy Policy Act of 2005 and replaced by PUHCA of 2005, effective February 8, 2006. CMS Energy, Consumers and their subsidiaries are subject to regulation by various federal, state, local and foreign governmental agencies, including those described below.
MICHIGAN PUBLIC SERVICE COMMISSION
Consumers is subject to the MPSC's jurisdiction, which regulates public utilities in Michigan with respect to retail utility rates, accounting, utility services, certain facilities and various other matters. The MPSC also has rate jurisdiction over several limited liability companies in which CMS Gas Transmission has ownership interests. These companies own, or will own, and operate intrastate gas transmission pipelines.
The Attorney General, ABATE, and the MPSC staff typically intervene in MPSC electric- and gas-related proceedings concerning Consumers. For many years, most significant MPSC orders affecting Consumers have been appealed. Certain appeals from the MPSC orders are pending in the Court of Appeals.
RATE PROCEEDINGS: In 2005, the MPSC issued an order that established the electric authorized rate of return on common equity at 11.15 percent.
MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the retail electric and gas utility businesses has undergone significant changes. In 2000, the Michigan Legislature enacted the Customer Choice Act. The Customer Choice Act provides that as of January 2002, all electric customers have the choice to buy generation service from an alternative electric supplier. The Customer Choice Act also imposes rate reductions, rate freezes and rate caps, which expired at the end of 2005. For additional information regarding the Customer Choice Act, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING.
Consumers transports the natural gas commodity that is sold to some customers by competitors like gas producers, marketers and others. Pursuant to a gas customer choice program that Consumers implemented, as of April 2003 all of Consumers' gas customers were eligible to select an alternative gas commodity supplier. Consumers' current GCR mechanism allows it to recover from its customers all prudently incurred costs to purchase natural gas and transport it to Consumers' facilities. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- CONSUMERS' GAS UTILITY RATE MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- GAS RATE MATTERS.
FEDERAL ENERGY REGULATORY COMMISSION
The FERC has exercised limited jurisdiction over several independent power plants in which CMS Generation has ownership interests, as well as over CMS ERM. Among other things, FERC jurisdiction relates to the acquisition, operation and disposal of certain assets and facilities and to the service provided and rates charged. The FERC also has limited jurisdiction over CMS Energy with respect to certain acquisitions of assets
and other holding company matters. Some of Consumers' gas business is also subject to regulation by the FERC, including a blanket transportation tariff pursuant to which Consumers can transport gas in interstate commerce.
The FERC also regulates certain aspects of Consumers' electric operations including compliance with FERC accounting rules, wholesale rates, operation of licensed hydro-electric generating plants, transfers of certain facilities, and corporate mergers and issuance of securities. The FERC is currently soliciting comments on whether it should exercise jurisdiction over power marketers like CMS ERM, requiring them to follow the 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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- NUCLEAR PLANT DECOMMISSIONING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR PLANT DECOMMISSIONING.
OTHER REGULATION
The Secretary of Energy regulates the importation and exportation of natural gas and has delegated various aspects of this jurisdiction to the FERC and the DOE's Office of Fossil Fuels.
Pipelines owned by system companies are subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulates the safety of gas pipelines. Consumers is also subject to the Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum pipelines.
CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE
CMS Energy, Consumers and their subsidiaries are subject to various federal, state and local regulations for environmental quality, including air and water quality, waste management, zoning and other matters.
CMS Energy has significant possible liability for its obligations associated with Bay Harbor. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Consumers has installed and is currently installing modern emission controls at its electric generating plants and has converted and is converting electric generating units to burn cleaner fuels. Consumers expects that the cost of future environmental compliance, especially compliance with clean air laws, will be significant because of EPA regulations and proposed regulations regarding nitrogen oxide, particulate-related emissions, and mercury. These regulations will require Consumers to make significant capital expenditures.
Consumers is in the process of closing older ash disposal areas at two plants. Construction, operation, and closure of a modern solid waste disposal area for ash can be expensive, because of strict federal and state requirements. In order to significantly reduce ash field closure costs, Consumers has worked with others to use bottom ash and fly ash as part of temporary and final cover for ash disposal areas instead of native materials, in cases where such use of bottom ash and fly ash is compatible with environmental standards. To reduce disposal volumes, Consumers sells coal ash for use as a filler for asphalt, as feedstock for the manufacture of Portland cement, 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 cleanup costs or environmental damages, such as claims for air pollution, damage to sites owned by CMS Energy or Consumers, and for some past PCB contamination and for some long-term storage or disposal of pollutants.
For additional information concerning environmental matters, including estimated capital expenditures to reduce nitrogen oxide related emissions, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- ELECTRIC ENVIRONMENTAL ESTIMATES and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- ELECTRIC ENVIRONMENTAL ESTIMATES.
CMS ENERGY AND CONSUMERS COMPETITION
ELECTRIC COMPETITION
Consumers' electric utility business experiences actual and potential competition from many sources, both in the wholesale and retail markets, as well as in electric generation, electric delivery and retail services.
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' 2005 revenues from electric utility operations. Consumers believes future loss of wholesale for resale transactions will be insignificant.
Price is the principal method of competition for electric generation services. The Customer Choice Act gives all electric customers the right to buy generation service from an alternative electric supplier. In June 2004, the MPSC granted Consumers recovery of implementation costs incurred for the Electric Customer Choice program. In November 2004, the MPSC adopted a mechanism pursuant to the Customer Choice Act to provide for recovery of stranded costs that occur when customers leave Consumers' system to purchase electricity from alternative electric suppliers. In January 2006, the MPSC approved cost-based retail open access distribution tariffs. A significant decrease in retail electric competition occurred in 2005 due to changes in market conditions, including increased uncertainty and volatility in fuel commodity prices. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of Consumers' total distribution load. It is difficult to predict future ROA customer trends.
In addition to retail electric customer choice, Consumers has competition or potential competition from:
- 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 from alternate fuels and energy sources, such as propane, oil and electricity.
INSURANCE
CMS Energy and its subsidiaries, including Consumers, maintain insurance coverage similar to comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and exclusions that might not fully compensate CMS Energy for all losses. A portion of each loss is generally assumed by CMS Energy in the form of deductibles and self-insured retentions that, in some cases, are substantial. As CMS Energy renews its policies it is possible that some of the insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets.
For a discussion of nuclear insurance coverage, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS.
EMPLOYEES
CMS ENERGY
As of December 31, 2005, CMS Energy and its wholly owned subsidiaries, including Consumers, had 8,713 full-time equivalent employees. Included in the total are 3,672 employees who are covered by union contracts.
CONSUMERS
As of December 31, 2005, Consumers and its subsidiaries had 8,114 full-time equivalent employees. Included in the total are 3,339 full-time operating, maintenance and construction employees and 327 full-time and part-time call center employees who are represented by the Utility Workers Union of America.
CMS ENERGY EXECUTIVE OFFICERS
(as of February 1, 2006)
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* From 1993 until July of 2004, Mr. Brunner was Assistant General Counsel of Consumers.
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 19, 2006).
CONSUMERS EXECUTIVE OFFICERS
(as of February 1, 2006)
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* From 1993 until July of 2004, Mr. Brunner was Assistant General Counsel of Consumers.
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 19, 2006).
AVAILABLE INFORMATION
CMS Energy's internet address is www.cmsenergy.com. You can access free of charge on our web site all of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act. Such reports are available as soon as practical after they are electronically filed with the SEC. Also on our web site are our:
- Corporate Governance Principles;
- 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.
You may also read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington DC, 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address is http://www.sec.gov.
ITEM 1A.
ITEM 1A. RISK FACTORS
RISKS RELATED TO CMS ENERGY
CMS ENERGY DEPENDS ON DIVIDENDS FROM ITS SUBSIDIARIES TO MEET ITS DEBT SERVICE OBLIGATIONS.
Due to its holding company structure, CMS Energy depends on dividends from its subsidiaries to meet its debt obligations. Restrictions contained in Consumers' preferred stock provisions and other legal restrictions, such as certain terms in its articles of incorporation, limit Consumers' ability to pay dividends or acquire its own stock from CMS Energy. As of December 31, 2005, the most restrictive provisions in its financing documents allowed Consumers to pay an aggregate of $300 million in dividends to CMS Energy during any year. At December 31, 2005 Consumers had $179 million of unrestricted retained earnings available to pay common stock dividends. If sufficient dividends are not paid to CMS Energy by its subsidiaries, CMS Energy may not be able to generate the funds necessary to fulfill its cash obligations, thereby adversely affecting its liquidity and financial condition.
CMS ENERGY HAS SUBSTANTIAL INDEBTEDNESS THAT COULD LIMIT ITS FINANCIAL FLEXIBILITY AND HENCE ITS ABILITY TO MEET ITS DEBT SERVICE OBLIGATIONS.
As of December 31, 2005, CMS Energy had outstanding approximately $2.527 billion aggregate principal amount of indebtedness, including approximately $178 million of subordinated indebtedness relating to its convertible preferred securities but excluding approximately $4.888 billion of indebtedness of its subsidiaries. In May 2005, CMS Energy entered into the Sixth Amended and Restated Credit Agreement in the amount of approximately $300 million. As of December 31, 2005, there were approximately $96 million of letters of credit outstanding under the Sixth Amended and Restated Credit Agreement. CMS Energy and its subsidiaries may incur additional indebtedness in the future.
The level of CMS Energy's present and future indebtedness could have several important effects on its future operations, including, among others:
- a significant portion of its cash flow from operations will be dedicated to the payment of principal and interest on its indebtedness and will not be available for other purposes;
- covenants contained in its existing debt arrangements require it to meet certain financial tests, which may affect its flexibility in planning for, and reacting to, changes in its business;
- its ability to obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other purposes may be limited;
- it may be at a competitive disadvantage to its competitors that are less leveraged; and
- its vulnerability to adverse economic and industry conditions may increase.
CMS Energy's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon its future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting its operations, many of which are beyond its control. CMS Energy cannot assure you that its business will continue to generate sufficient cash flow from operations to service its indebtedness. If it is unable to generate sufficient cash flows from operations, it may be required to sell additional assets or obtain additional financings. CMS Energy cannot assure that additional financing will be available on commercially acceptable terms or at all.
There can be no assurance that the requirements of CMS Energy's existing debt arrangements or other indebtedness will be met in the future. Failure to comply with those covenants may result in a default with respect to the related debt and could lead to acceleration of that debt or any instruments evidencing indebtedness that contain cross-acceleration or cross-default provisions.
In such a case, there can be no assurance that CMS Energy would be able to refinance or otherwise repay that indebtedness.
CMS ENERGY CANNOT PREDICT THE OUTCOME OF CLAIMS REGARDING ITS PARTICIPATION IN THE DEVELOPMENT OF BAY HARBOR OR OTHER LITIGATION IN WHICH SUBSTANTIAL MONETARY CLAIMS ARE INVOLVED.
As part of the development of Bay Harbor by certain subsidiaries of CMS Energy, which went forward under an agreement with the MDEQ, a third party constructed a golf course over several abandoned cement kiln dust (CKD) piles, left over from the former cement plant operation on the Bay Harbor site. Pursuant to the agreement with the MDEQ, CMS Energy constructed a water collection system to recover seep water from one of the CKD piles. In 2002, CMS Energy sold its interest in Bay Harbor, but retained its obligations under previous environmental indemnifications entered into at the inception of the project.
In September 2004, the MDEQ issued a notice of noncompliance (NON), after finding high-pH seep water in Lake Michigan adjacent to the property. The MDEQ also found higher than acceptable levels of heavy metals, including mercury, in the seep water.
In February 2005, the EPA executed an Administrative Order on Consent (AOC) to address problems at Bay Harbor, upon the consent of CMS Land Company, a subsidiary of Enterprises and CMS Capital, LLC, a subsidiary of CMS Energy. Under the AOC, CMS Land Company and CMS Capital, LLC are 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 "removal action work 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. The EPA approved a final removal action work plan in September 2005.
The EPA-approved removal action work plan provides for fencing of affected beachfront areas and installing an underground leachate collection system, among other elements. The EPA's approvals also specify that a backup "containment and isolation system," involving dams or barriers in the lake, could be required in certain areas, if the collection system is ineffective. In addition, there are indications that CKD may be located on the beach at the west end of the collection system installation. As a result, construction in the affected area has been halted pending further investigation. CMS Energy has worked out a schedule with the EPA to perform further investigation of these conditions and will deliver a conceptual design to the EPA for a remediation system. CMS Energy is presently engaged in negotiations with the EPA and the MDEQ concerning potential interim remediation activities for the Eastern CKD pile, which may include a carbon dioxide injection system to neutralize high-pH materials and/or a collection system or systems.
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. Several landowners have threatened litigation in the event their demands are not met and owners of one parcel have filed a lawsuit in Emmet County Circuit Court against CMS Energy and several of its subsidiaries, as well as Bay Harbor Company LLC and David Johnson, one of the developers at Bay Harbor. 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 has entered into various access, purchase and settlement agreements with several of the affected landowners at Bay Harbor and continues negotiations with other landowners for access as necessary to implement remediation measures. CMS Energy will defend vigorously any property damage and personal injury claims or lawsuits.
CMS Energy originally recorded a liability for its obligations associated with this matter in the amount of $45 million in the fourth quarter of 2004. Under the AOC, CMS Land Company is presently conducting a remedial investigation of the site, which includes the gathering and analysis of data to be utilized in arriving at a permanent fix. Based on the evaluation of recent construction events and site-related data, CMS Energy has increased its cost projections and reserves to $85 million. An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy's financial condition and liquidity and could negatively impact CMS Energy's financial results. CMS Energy cannot predict the ultimate cost or outcome of this matter.
In addition to the litigation and proceedings discussed above, CMS Energy or various of its subsidiaries are parties in other pending litigation in which substantial monetary damages are sought. An adverse outcome in one or more of these cases could, depending on the timing and size of any award and the availability of insurance or reimbursement from third parties, have an adverse effect on CMS Energy's financial condition, liquidity or results of operations.
CMS ENERGY RETAINS CONTINGENT LIABILITIES IN CONNECTION WITH ITS ASSET SALES.
The agreements CMS Energy enters into for the sale of assets customarily include provisions whereby it is required to:
- retain specified preexisting liabilities such as for taxes and pensions;
- indemnify the buyers against specified risks, including the inaccuracy of representations and warranties it makes; and
- require payments to the buyers depending on the outcome of post-closing adjustments, audits or other reviews.
Many of these contingent liabilities can remain open for extended periods of time after the sales are closed. Depending on the extent to which the buyers may ultimately seek to enforce their rights under these contractual provisions, and the resolution of any disputes CMS Energy may have concerning them, these liabilities could have a material adverse effect on its financial condition, liquidity and results of operations.
CMS Energy has received a request for indemnification from 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 the purchaser of CMS Oil and Gas has submitted a response to the government rejecting the claim. An adverse outcome of this claim could have a material adverse effect on CMS Energy's financial condition, liquidity and results of operations.
CMS ENERGY HAS MADE SUBSTANTIAL INTERNATIONAL INVESTMENTS THAT ARE SUBJECT TO POSSIBLE NATIONALIZATION, EXPROPRIATION OR INABILITY TO CONVERT CURRENCY.
CMS Energy's investments in selected international markets in electric generating facilities, natural gas pipelines and electric distribution systems face a number of risks inherent in acquiring, developing and owning these types of international facilities. Although CMS Energy maintains insurance for various risk exposures, including political risk from possible nationalization, expropriation or inability to convert currency, it is exposed to some risks that include local political and economic factors over which it has no control, such as changes in foreign governmental and regulatory policies (including changes in industrial regulation and control and changes in taxation), changing political conditions and international monetary fluctuations. In some cases an investment may have to be abandoned or disposed of at a loss. These factors could have a significant adverse effect on the financial results of the affected subsidiary and CMS Energy's financial position and results of operations.
International investments of the type CMS Energy has made are subject to the risk that the investments may be expropriated or that the required agreements, licenses, permits and other approvals may be changed or terminated in violation of their terms. These kinds of changes could result in a partial or total loss of CMS Energy's investment.
The local foreign currency may be devalued, the conversion of the currency may be restricted or prohibited or other actions, such as increases in taxes, royalties or import duties, may be taken which adversely affect the value and the recovery of CMS Energy's investment.
RISKS RELATED TO CMS ENERGY AND CONSUMERS
CMS ENERGY AND CONSUMERS HAVE FINANCING NEEDS AND THEY MAY BE UNABLE TO SUCCESSFULLY ACCESS BANK FINANCING OR THE CAPITAL MARKETS.
Consumers expects to incur significant costs for capital expenditures, including future environmental regulation compliance, especially compliance with clean air laws. See "CMS Energy and Consumers could incur significant capital expenditures to comply with environmental standards and face difficulty in recovering these costs on a current basis" below. As of December 31, 2005, Consumers had incurred $605 million in capital expenditures to comply with these regulations and future capital expenditures may total approximately $210 million between 2006 and 2011.
CMS Energy and Consumers continue to be challenged by the substantial increase in natural gas prices. Although Consumers' reasonably and prudently incurred natural gas purchases are recoverable from its utility customers, as gas prices increase, the amount it pays for natural gas stored as inventory will require additional liquidity due to the timing of the cost recoveries from its customers. Consumers anticipates that it will need a substantial amount of cash in the summer of 2006 to purchase storage for natural gas for winter 2006-2007. See "The combined effects of substantially higher natural gas prices, restrictions on Consumers' ability to issue first mortgage bonds and possible power purchase supply cost recovery delays may have a negative effect on Consumers' short-term liquidity" below. CMS Energy and Consumers could also be required to make additional cash contributions to their employee pension and benefit plans and become subject to liquidity demands pursuant to commercial commitments under guarantees, indemnities and letters of credit. Management is actively pursuing plans to sell assets. There can be no assurances that this business plan will be successful and failure to achieve its goals could have a material adverse effect on CMS Energy's and Consumers' liquidity and operations.
CMS Energy continues to explore financing opportunities to supplement its financial plan. These potential opportunities include: refinancing its bank credit facilities, entering into leasing arrangements and refinancing and/or issuing new capital markets debt, preferred stock and/or common equity. CMS Energy cannot guarantee the capital market's acceptance of its securities or predict the impact of factors beyond its control, such as actions of rating agencies. If CMS Energy is unable to access bank financing or the capital markets to incur or refinance indebtedness, there could be a material adverse effect upon its liquidity and operations.
Similarly, Consumers currently plans to seek funds through the capital markets and commercial lenders. Entering into new financings is subject in part to capital market receptivity to utility industry securities in general and to Consumers' securities issuances in particular. Consumers cannot guarantee the capital market's acceptance of its securities or predict the impact of factors beyond its control, such as actions of rating agencies. If Consumers is unable to access bank financing or the capital markets to incur or refinance indebtedness, there could be a material adverse effect upon its liquidity and operations.
Certain of CMS Energy's securities and those of its affiliates, including Consumers, are rated by various credit rating agencies. Any reduction or withdrawal of one or more of its credit ratings could have a material adverse impact on CMS Energy's ability to access capital on acceptable terms and maintain commodity lines of credit and could make its cost of borrowing higher. If it is unable to maintain commodity lines of credit, CMS Energy may have to post collateral or make prepayments to certain of its suppliers pursuant to existing contracts with them. Further, any adverse developments to Consumers, which provides dividends to CMS Energy, that result in a lowering of Consumers' credit ratings could have an adverse effect on CMS Energy's credit ratings. CMS Energy and Consumers cannot assure you that any of their current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.
On August 2, 2005, the IRS issued Revenue Ruling 2005-53 and regulations to provide guidance with respect to the use of the "simplified service cost" method of tax accounting. CMS Energy and Consumers use this tax accounting method, generally allowed by the IRS under section 263A of the Internal Revenue Code, with respect to the allocation of certain corporate overheads to the tax basis of self-constructed utility assets. Under the IRS guidance, significant issues with respect to the application of this method remain unresolved and subject to dispute. However, the effect of the IRS's position may be to require CMS Energy either (1) to repay a portion of previously received tax benefits, or (2) to add back to taxable income, half in each of 2005 and 2006, a significant
portion of previously deducted overheads. The impact of this matter on future earnings, cash flows, or present NOL carryforwards remains uncertain, but could be material. CMS Energy and Consumers have recorded a reduction in NOL carryforwards of $359 million in 2005, and a corresponding reduction in deferred taxes related to property, to reflect the estimated 2005 effect of the new regulation. CMS Energy and Consumers cannot predict the outcome of this matter.
PERIODIC REVIEWS OF THE VALUES OF CMS ENERGY'S AND CONSUMERS' ASSETS COULD RESULT IN ADDITIONAL ACCOUNTING CHARGES SUCH AS THE RECENT ASSET IMPAIRMENT CHARGES THEY TOOK RELATING TO THEIR INTEREST IN THE MCV PARTNERSHIP.
CMS Energy and Consumers are required by GAAP to periodically review the carrying value of their assets, including those that may be sold. Market conditions, the operational characteristics of their assets and other factors could result in recording additional impairment charges for their assets, which could have an adverse effect on their stockholders' equity and their access to additional financing. In addition, they may be required to record impairment charges and/or foreign currency translation losses at the time they sell assets, depending on the sale prices they are able to secure and other factors.
The MCV Partnership's costs of producing electricity are tied to the price of natural gas, but its revenues do not vary with changes in the price of natural gas. In 2005, NYMEX forward natural gas price forecasts for the years 2005 through 2010 increased substantially. Additionally, other independent natural gas long-term forward price forecasting organizations indicated their intention to raise their forecasts for the price of natural gas generally over the entire long-term forecast horizon beyond 2010. CMS Energy's and Consumers' analysis and assessment of this information suggested that forward natural gas prices for the period from 2006 through 2010 could average approximately $9 per mcf. Further, this information indicated that natural gas prices could average approximately $6.50 per mcf over the long term beyond 2010. As a result, in 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and determined that an impairment analysis, considering revised forward natural gas price assumptions, was required. In its impairment analysis, the MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows at a 4.3 percent risk free interest rate. The carrying value of the MCV Partnership's fixed assets exceeded the estimated fair value, resulting in an impairment charge of $1.159 billion to recognize the reduction in fair value of the MCV Facility's fixed assets. As a result, Consumers' 2005 net income was reduced by $369 million after considering tax effects and minority interest. The MCV Partnership's fixed assets, which are included on Consumers' Consolidated Balance Sheets and reported by CMS Energy under the Enterprises business segment, after reflecting the impairment charge, are valued at $224 million at December 31, 2005.
The impairment of the MCV Facility, and any potential future impairment of the MCV Facility, will likely decrease the amount of equity investment recognized in future electric and gas rate orders. Lower equity investment may result in a reduced revenue requirement. However, CMS Energy and Consumers cannot predict the outcome of any future rate cases, which may be lower or higher based on several factors, including the amount of equity investment and related risk.
If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected and could result in the MCV Partnership failing to meet its obligations under the sale and leaseback transactions and other contracts and could result in a potential impairment of the FMLP. At December 31, 2005, Consumers' investment in the FMLP was $235 million.
Consumers' 49 percent interest in the MCV Partnership is held through Consumers' wholly-owned subsidiary, CMS Midland. The severe adverse change in the anticipated economics of the MCV Partnership operations discussed herein also led to the decision to impair certain assets carried on the balance sheet of CMS Midland. These assets represented interest capitalized during the construction of the MCV Facility, which were being amortized over the life of the MCV Facility. In the third quarter of 2005, Consumers recorded an impairment charge of $25 million ($16 million, net of tax) to reduce the carrying amount of these assets to zero.
The total of the CMS Midland impairment and the MCV Partnership impairment discussed above is $1.184 billion, before tax, and $385 million net of taxes and minority interest.
THE COMBINED EFFECTS OF SUBSTANTIALLY HIGHER NATURAL GAS PRICES, RESTRICTIONS ON CONSUMERS' ABILITY TO ISSUE FIRST MORTGAGE BONDS AND POSSIBLE POWER PURCHASE SUPPLY COST RECOVERY DELAYS MAY HAVE A NEGATIVE EFFECT ON CONSUMERS' SHORT-TERM LIQUIDITY.
Natural gas prices continue to increase substantially. Although Consumers' natural gas purchases are recoverable from its utility customers, as gas prices increase, the amount it pays for natural gas stored as inventory will require additional liquidity due to the timing of the cost recoveries from its customers. Due to the high natural gas prices, Consumers' ability to collect accounts receivable from its gas customers may be negatively impacted. In addition, if natural gas prices increase or stay at current levels, Consumers will require significant additional liquidity in the summer of 2006 to fill its gas storage facilities in preparation for the 2006-2007 heating season.
Due to the adverse impact of the MCV Partnership asset impairment charge recorded in September 2005, Consumers' ability to issue FMB as primary obligations or as collateral for financing is expected to be limited to $298 million through September 30, 2006. FMB have been a primary source of financing for Consumers. After September 30, 2006, Consumers' ability to issue FMB in excess of $298 million is based on achieving a two-times FMB interest coverage ratio.
Consumers is entitled to recover its reasonably and prudently incurred power supply costs pursuant to the PSCR process. In September 2005, Consumers submitted its 2006 PSCR plan filing to the MPSC. In November 2005, it submitted an amended 2006 PSCR plan to the MPSC to include higher estimates for certain transmission and coal supply costs. In December 2005, the MPSC issued an order that temporarily excludes the increased portion of these costs from Consumers' PSCR charge, which began in January 2006. The order also includes a one mill per kWh reduction in the PSCR charge. To the extent that Consumers incurs and is unable to collect these costs in a timely manner, its cash flows from electric utility operations will be affected negatively. Consumers cannot predict the outcome of the PSCR proceeding.
CMS ENERGY AND CONSUMERS MAY BE ADVERSELY AFFECTED BY REGULATORY INVESTIGATIONS AND A LAWSUIT REGARDING "ROUND-TRIP" TRADING BY CMS MST AS WELL AS CIVIL LAWSUITS REGARDING PRICING INFORMATION THAT CMS MST AND CMS FIELD SERVICES PROVIDED TO MARKET PUBLICATIONS.
As a result of round-trip trading transactions (simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price) at CMS MST, CMS Energy is under investigation by the DOJ. CMS Energy has also received subpoenas from U.S. Attorneys' Offices regarding investigations of those trades. In addition, CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates, have been named in numerous securities class action lawsuits by individuals who allege that they purchased CMS Energy securities during a purported class period. The cases have been consolidated into a single lawsuit. The consolidated lawsuit generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, a motion was granted dismissing Consumers and three of the individual defendants, but the court denied the motions to dismiss for CMS Energy and the 13 remaining individual defendants. Plaintiffs filed a motion for class certification on April 15, 2005 and an amended motion for class certification on June 20, 2005. On November 29, 2005, the court denied a further motion to dismiss filed by CMS Energy and denied a motion by the plaintiffs for partial summary judgment.
In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy relating to round-trip trading. The order did not assess a fine and CMS Energy neither admitted nor denied the order's findings.
CMS Energy has notified appropriate regulatory and governmental agencies that some employees at CMS MST and CMS Field Services (now Cantera Gas Company) 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. On November 25, 2003, the CFTC issued a settlement order regarding this matter. CMS MST and CMS Field Services agreed to pay a
fine to the CFTC totaling $16 million. CMS Energy neither admitted nor denied the findings of the CFTC in the settlement order. 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 those acts, compel compliance with the Commodities Exchange Act and impose monetary penalties. CMS Energy is currently advancing legal defense costs to the two individuals in accordance with existing indemnification policies.
CMS Energy has also been named as a defendant in a number of gas industry civil lawsuits regarding inaccurate gas trade reporting that include claims alleging manipulation of NYMEX natural gas futures and options prices, price-fixing conspiracies and artificial inflation of natural gas retail prices in California, Kansas and Tennessee.
CMS Energy and Consumers cannot predict the outcome of the DOJ investigations and the lawsuits. It is possible that the outcome in one or more of the investigations or the lawsuits could adversely affect CMS Energy's and Consumers' financial condition, liquidity or results of operations.
CMS ENERGY AND CONSUMERS MAY BE NEGATIVELY IMPACTED BY THE RESULTS OF AN EMPLOYEE BENEFIT PLAN LAWSUIT.
CMS Energy and Consumers are defendants, along with 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 their 401(k) plan. The two cases, filed in July 2002 in the United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended and consolidated complaint has been 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. The plaintiffs also seek other equitable relief and legal fees. The judge has conditionally granted plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than mid-2006 in the absence of an intervening settlement of the lawsuits. Settlement negotiations among counsel for the parties and CMS Energy's fiduciary insurance carrier are ongoing. In the absence of such a settlement, CMS Energy and Consumers will defend themselves vigorously in this litigation but cannot predict its outcome.
It is possible that an adverse outcome in this lawsuit could adversely affect CMS Energy's and Consumers' financial condition, liquidity or results of operations.
REGULATORY CHANGES AND OTHER DEVELOPMENTS HAVE RESULTED AND COULD CONTINUE TO RESULT IN INCREASED COMPETITION IN THE DOMESTIC ENERGY BUSINESS. GENERALLY, INCREASED COMPETITION THREATENS MARKET SHARE IN CERTAIN SEGMENTS OF CMS ENERGY'S BUSINESS AND CAN REDUCE ITS AND CONSUMERS' PROFITABILITY.
Pursuant to the Customer Choice Act, as of January 1, 2002, all electric customers in Michigan had the choice of buying electric generation service from Consumers or an alternative electric supplier. Consumers had experienced, and could experience in the future, a significant increase in competition for generation services due to the introduction of ROA. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents 7 percent of Consumers' total distribution load. It is difficult to predict the total amount of electric supply load that may be lost to competitor suppliers in the future.
ELECTRIC INDUSTRY REGULATION COULD ADVERSELY AFFECT CMS ENERGY'S AND CONSUMERS' BUSINESS, INCLUDING THEIR ABILITY TO RECOVER COSTS FROM THEIR CUSTOMERS.
Federal and state regulation of electric utilities has changed dramatically in the last two decades and could continue to change over the next several years. These changes could adversely affect CMS Energy's and Consumers' business, financial condition and profitability.
There are multiple proceedings pending before the FERC involving transmission rates, regional transmission organizations and electric bulk power markets and transmission. FERC is also reviewing the standards under which electric utilities are allowed to participate in wholesale power markets without price restrictions. CMS
Energy and Consumers cannot predict the impact of these electric industry restructuring proceedings on their financial position, liquidity or results of operations.
CMS ENERGY AND CONSUMERS COULD INCUR SIGNIFICANT CAPITAL EXPENDITURES TO COMPLY WITH ENVIRONMENTAL STANDARDS AND FACE DIFFICULTY IN RECOVERING THESE COSTS ON A CURRENT BASIS.
CMS Energy, Consumers, and their subsidiaries are subject to costly and increasingly stringent environmental regulations. They expect that the cost of future environmental compliance, especially compliance with clean air and water laws, will be significant.
In 1998, the EPA issued regulations requiring the State of Michigan to further limit nitrogen oxide emissions at coal-fired electric plants. The EPA and State of Michigan regulations require Consumers to make significant capital expenditures estimated to be $815 million. As of December 2005, Consumers has incurred $605 million in capital expenditures to comply with these regulations and anticipates that the remaining $210 million of capital expenditures will be made in 2006 through 2011. These expenditures include installing selective catalytic reduction technology at four of its coal-fired electric plants. In addition to modifying coal-fired electric plants, Consumers compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $10 million per year, which Consumers expects to recover from customers through the PSCR process. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years.
The EPA recently adopted a Clean Air Interstate Rule that requires additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. The rule involves a two-phase program to reduce emissions of sulfur dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule will require that Consumers run its selective catalytic control technology units year-round beginning in 2009 and may require that it purchase additional nitrogen oxide allowances beginning in 2009. In addition to the selective catalytic control technology installed to meet the nitrogen oxide standards, Consumers' current plan includes installation of flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to meet the Phase I reduction requirements of the Clean Air Interstate Rule at costs similar to those to comply with nitrogen oxide standards.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric power plants by 2010 and further reductions by 2018. While the industry has not reached a consensus on the technical methods for curtailing mercury emissions, Consumers' capital and operating costs for mercury emissions reductions are expected to be significantly less than what was required for selective catalytic reduction technology used for nitrogen oxide compliance.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to certain aspects of EPA's Clean Air Mercury Rule, asserting that the rule is inadequate. The MDEQ has not indicated the direction that it will pursue to meet or exceed the EPA requirements through a state rulemaking. Consumers is actively participating in dialog with the MDEQ regarding potential paths for controlling mercury emissions and meeting the EPA requirements. In October 2005, the EPA announced it would reconsider certain aspects of the Clean Air Mercury Rule. Consumers cannot predict the outcome of this proceeding.
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. CMS Energy and Consumers cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any of these rules.
To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. CMS Energy and Consumers cannot estimate the potential effect of federal or state level greenhouse gas policy on their future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, CMS Energy and Consumers stay abreast of and engage in greenhouse gas policy developments and will continue to assess and respond to the potential implications on their business operations.
These and other required environmental expenditures, if not recovered from customers in Consumers' rates, may require CMS Energy and/or Consumers to seek significant additional financing to fund these expenditures and could strain their cash resources.
CMS ENERGY'S AND CONSUMERS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO RISKS THAT ARE BEYOND THEIR CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE TERRORIST ATTACKS OR RELATED ACTS OF WAR.
The cost of repairing damage to CMS Energy's and Consumers' facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of insurance recoveries and reserves established for these repairs, may adversely impact their results of operations, financial condition and cash flows. The occurrence or risk of occurrence of future terrorist activity and the high cost or potential unavailability of insurance to cover this terrorist activity may impact their results of operations and financial condition in unpredictable ways. These actions could also result in disruptions of power and fuel markets. In addition, their natural gas distribution system and pipelines could be directly or indirectly harmed by future terrorist activity.
CONSUMERS' OWNERSHIP OF A NUCLEAR GENERATING FACILITY CREATES RISK RELATING TO NUCLEAR ENERGY.
Consumers owns the Palisades nuclear power plant and is, therefore, subject to the risks of nuclear generation, including the risks associated with the operation of plant facilities and the storage and disposal of spent fuel and other radioactive waste. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, if a serious nuclear incident were to occur at Consumers' plant, it could harm Consumers' results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
In December 2005, Consumers announced plans to sell the Palisades plant in a competitive bid process expected to lead to a sale in 2007.
CONSUMERS CURRENTLY UNDERRECOVERS IN ITS RATES ITS PAYMENTS TO THE MCV PARTNERSHIP FOR CAPACITY AND ENERGY, AND IS ALSO EXPOSED TO FUTURE CHANGES IN THE MCV PARTNERSHIP'S FINANCIAL CONDITION THROUGH ITS EQUITY AND LESSOR INVESTMENTS.
The MCV PPA expires in 2025. Under the MCV PPA, variable energy payments to the MCV Partnership are based on the cost of coal burned at Consumers' coal plants and its operation and maintenance expenses. However, the MCV Partnership's costs of producing electricity are tied to the cost of natural gas. Natural gas prices have increased substantially in recent years and throughout 2005. In 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and recorded an impairment. For additional details on the impairment of the MCV Facility, see "Periodic reviews of the values of CMS Energy's and Consumers' assets could result in additional accounting charges such as the recent asset impairment charges they took relating to their interest in the MCV Partnership" above.
Further, the cost that Consumers incurs under the MCV PPA exceeds the recovery amount allowed by the MPSC. Underrecoveries of capacity and fixed energy payments totaled $59 million in 2005. Consumers estimates underrecoveries of $55 million in 2006 and $39 million in 2007. After September 15, 2007, it expects to claim relief under the regulatory out provision in the MCV PPA, thereby limiting its capacity and fixed energy payments to the MCV Partnership to the amounts that it collects from its customers. The MCV Partnership has indicated that it may take issue with Consumers' exercise of the regulatory out clause after September 15, 2007. Consumers believes 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 financial performance of the MCV Partnership.
In January 2005, Consumers implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed
for rehearing of the MPSC order approving the RCP. The Attorney General also filed an appeal with the Michigan Court of Appeals. Consumers cannot predict the outcome of these matters.
CMS Energy and Consumers cannot estimate, at this time, the impact of these issues on Consumers' future earnings or cash flow from its interest in the MCV Partnership. The ability to develop a new long-term strategy with respect to the MCV Facility, the future price of natural gas and an MPSC decision related to Consumers' recovery of capacity payments are the three most significant variables in the analysis of the MCV Partnership's future financial performance. It is not presently possible to predict the success of the ability to develop a new long -- term strategy with respect to the MCV Facility, the future price of natural gas, or the actions of the MPSC in 2007 or later. For these reasons, at this time CMS Energy and Consumers cannot predict the impact of these issues on Consumers' future earnings or cash flows or on the value of its equity interest in the MCV Partnership and CMS Energy's lessor interest in the FMLP.
CONSUMERS' ENERGY RISK MANAGEMENT STRATEGIES MAY NOT BE EFFECTIVE IN MANAGING FUEL AND ELECTRICITY PRICING RISKS, WHICH COULD RESULT IN UNANTICIPATED LIABILITIES TO CONSUMERS OR INCREASED VOLATILITY OF ITS EARNINGS.
Consumers is exposed to changes in market prices for natural gas, coal, electricity and emission credits. Prices for natural gas, coal, electricity and emission credits may fluctuate substantially over relatively short periods of time and expose Consumers to commodity price risk. A substantial portion of Consumers' operating expenses for its plants consists of the costs of obtaining these commodities. Consumers manages these risks using established policies and procedures, and it may use various contracts to manage these risks, including swaps, options, futures and forward contracts. No assurance can be made that these strategies will be successful in managing Consumers' pricing risk, or that they will not result in net liabilities to Consumers as a result of future volatility in these markets.
Natural gas prices in particular have historically been volatile. To manage market risks associated with the volatility of natural gas prices, the MCV Partnership maintains a gas hedging program. The MCV Partnership enters into natural gas futures contracts, option contracts and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being used principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize the MCV Partnership's existing gas supply, storage and transportation arrangements. Consumers also routinely enters into contracts to offset its positions, such as hedging exposure to the risks of demand, market effects of weather and changes in commodity prices associated with its gas distribution business. These positions are taken in conjunction with the GCR mechanism, which allows Consumers to recover prudently incurred costs associated with those positions. However, neither Consumers nor the MCV Partnership always hedges the entire exposure of its operations from commodity price volatility. Furthermore, the ability to hedge exposure to commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, Consumers may not be able to execute its risk management strategies, which could result in greater open positions than preferred at a given time. To the extent that open positions exist, fluctuating commodity prices can improve or diminish CMS Energy's and Consumers' financial results and financial position.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
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 in this Item 2:
- BUSINESS -- GENERAL -- Consumers -- Consumers' Properties -- General;
- BUSINESS -- BUSINESS SEGMENTS -- Consumers Electric Utility -- Electric Utility Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Consumers Gas Utility -- Gas Utility Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Natural Gas Transmission -- Natural Gas Transmission Properties;
- BUSINESS -- BUSINESS SEGMENTS -- Independent Power Production -- Independent Power Production Properties; and
- BUSINESS -- BUSINESS SEGMENTS -- International Energy Distribution.
ITEM 3.
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 documents and data relating to the SEC's inquiry into payments made to the officials or relatives of officials of the government of Equatorial Guinea. On August 17, 2004, CMS Energy submitted its response, advising the SEC of the information and documentation it had available. On March 8, 2005, CMS Energy received a request from the SEC that CMS Energy voluntarily produce certain of such documents. CMS Energy has provided responsive documents to the SEC and will continue to provide such documents as it reviews its electronic records in further response to the SEC's request. The SEC subsequently issued a formal order of private investigation on this matter and on August 1, 2005, CMS Energy and several other companies who have conducted business in Equatorial Guinea received subpoenas from the SEC to provide documents regarding payments made to officials or relatives of officials of the government of Equatorial Guinea. CMS Energy is cooperating and has been and will continue to produce documents responsive to the subpoena.
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 Cornerstone complaint was subsequently consolidated with two similar complaints filed by other plaintiffs. 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. On September 30, 2005, the court entered an order granting plaintiffs' motion for class certification. Plaintiffs are seeking 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 of CMS Field Services to Cantera Gas Company. CMS Energy is required to indemnify Cantera Natural Gas, LLC with respect to this action.) Settlement negotiations among counsel for the parties are ongoing. In the absence of such a settlement, CMS MST and CMS Field Services will defend themselves vigorously in this litigation but cannot predict its outcome.
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 (including CMS Energy). The complaint alleged defendants entered into a price-fixing scheme by engaging in activities to manipulate the price of natural gas in California. The complaint alleged violations of the federal Sherman Act, the California Cartwright Act, and the California Business and Professions Code relating to unlawful, unfair and deceptive business practices. The complaint sought both actual and exemplary damages for alleged overcharges, attorneys fees and injunctive relief regulating defendants' future conduct relating to pricing and price reporting. In April 2004, a Nevada Multidistrict Litigation (MDL) Panel ordered the transfer of the Texas-Ohio case to a pending MDL matter in the Nevada federal district court that at the time involved seven complaints originally filed in various state courts in California. These complaints make allegations similar to those in the Texas-Ohio case regarding price reporting, although none contain a federal Sherman Act claim. In November 2004, those seven complaints, as well as a number of others that were originally filed in various state courts in California and subsequently transferred to the MDL proceeding, were remanded back to California state court. The Texas-Ohio case remained in Nevada federal district court, and defendants, with CMS Energy joining, filed a motion to dismiss. The court issued an order granting the motion to dismiss on April 8, 2005 and entered a judgment in favor of the defendants on April 11, 2005. Texas-Ohio has appealed the dismissal to the Ninth Circuit Court of Appeals.
Three federal putative class actions, Fairhaven Power Company v. Encana Corp. et al., Utility Savings & Refund Services LLP v. Reliant Energy Resources Inc. et al., and Abelman Art Glass v. Encana Corp. et al., all of which make allegations similar to those in the Texas-Ohio case regarding price manipulation and seek similar relief, were originally filed in the United States District Court for the Eastern District of California in September 2004, November 2004 and December 2004, respectively. The Fairhaven and Abelman Art Glass cases also include claims for unjust enrichment and a constructive trust. The three complaints were filed against CMS Energy and many of the other defendants named in the Texas-Ohio case. In addition, the Utility Savings case names CMS MST and Cantera Resources Inc. (Cantera Resources Inc. is the parent of Cantera Natural Gas, LLC and CMS Energy is required to indemnify Cantera Natural Gas, LLC and Cantera Resources Inc. with respect to these actions.)
The Fairhaven, Utility Savings and Abelman Art Glass cases have been transferred to the MDL proceeding, where the Texas-Ohio case was pending. Pursuant to stipulation by the parties and court order, defendants were not required to respond to the Fairhaven, Utility Savings and Abelman Art Glass complaints until the court ruled on defendants' motion to dismiss in the Texas-Ohio case. Plaintiffs subsequently filed a consolidated class action complaint alleging violations of federal and California antitrust laws. Defendants filed a motion to dismiss, arguing that the consolidated complaint should be dismissed for the same reasons as the Texas-Ohio case. The court issued an order granting the motion to dismiss on December 19, 2005 and entered judgment in favor of defendants on December 23, 2005. Plaintiffs have appealed the dismissal to the Ninth Circuit Court of Appeals.
Commencing in or about February 2004, 15 state law complaints containing allegations similar to those made in the Texas-Ohio case, but generally limited to the California Cartwright Act and unjust enrichment, were filed in various California state courts against many of the same defendants named in the federal price
manipulation cases discussed above. In addition to CMS Energy, CMS MST is named in all of the 15 state law complaints. Cantera Gas Company and Cantera Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in all but one complaint.
In February 2005, these 15 separate actions, as well as nine other similar actions that were filed in California state court but do not name CMS Energy or any of its former or current subsidiaries, were ordered coordinated with pending coordinated proceedings in the San Diego Superior Court. The 24 state court complaints involving price reporting were coordinated as Natural Gas Antitrust Cases V. Plaintiffs in Natural Gas Antitrust Cases V were ordered to file a consolidated complaint, but a consolidated complaint was filed only for the two putative class action lawsuits. On April 8, 2005, defendants filed a demurrer to the master class action complaint and the individual complaints and on May 13, 2005, plaintiffs filed a memorandum of points and authorities in opposition to defendants' federal preemption demurrer and motion to strike. Pursuant to a ruling dated June 29, 2005, the demurrer was overruled and the motion to strike was denied.
Samuel D. Leggett, et al v. Duke Energy Corporation, et al, a class action complaint brought on behalf of retail and business purchasers of natural gas in Tennessee, was filed in the Chancery Court of Fayette County, Tennessee in January 2005. The complaint contains claims for violations of the Tennessee Trade Practices Act based upon allegations of false reporting of price information by defendants to publications that compile and publish indices of natural gas prices for various natural gas hubs. The complaint seeks statutory full consideration damages and attorneys fees and injunctive relief regulating defendants' future conduct. The defendants include CMS Energy, CMS MST and CMS Field Services. On March 7, 2005, defendants removed the case to the United States District Court for the Western District of Tennessee, Western Division, and they filed a motion on May 20, 2005 to transfer the case to the MDL proceeding in Nevada. On April 6, 2005, plaintiffs filed a motion to remand the case back to the Chancery Court in Tennessee. On August 10, 2005, certain defendants, including CMS MST, filed a motion to dismiss, and CMS Energy and CMS Field Services filed a motion to dismiss for lack of personal jurisdiction. Plaintiffs have opposed the motions to dismiss. An order transferring the case to the MDL proceeding in Nevada was issued on or about August 11, 2005, and the motions to dismiss remain pending.
On November 20, 2005, CMS MST was served with a summons and complaint which named CMS Energy, CMS MST and CMS Field Services as defendants in a new putative class action filed in Kansas state court, Learjet, Inc., et al. v. Oneok, Inc., et al. Similar to the other actions that have been filed, the complaint alleges that during the putative class period, January 1, 2000 through October 31, 2002, defendants engaged in a scheme to violate the Kansas Restraint of Trade Act by knowingly reporting false or inaccurate information to the publications, thereby affecting the market price of natural gas. Plaintiffs, who allege they purchased natural gas from defendants and other for their facilities, are seeking statutory full consideration damages consisting of the full consideration paid by plaintiffs for natural gas. On December 7, 2005, the case was removed to the United States District Court for the District of Kansas and later that month a motion was filed to transfer the case to the MDL proceeding in Nevada. On January 6, 2006, plaintiffs filed a motion to remand the case to Kansas state court. On January 23, 2006, a conditional transfer order transferring the case to the MDL proceeding in Nevada was issued. On February 7, 2006, plaintiffs filed an opposition to the conditional transfer order.
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. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies.
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 has conditionally granted plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than mid-2006 in the absence of an intervening settlement of the lawsuits. Settlement negotiations among counsel for the parties and CMS Energy's fiduciary insurance carrier are ongoing. In the absence of such a settlement, CMS Energy and Consumers will defend themselves vigorously in this litigation but cannot predict its outcome.
SECURITIES CLASS ACTION LAWSUITS
Beginning on May 17, 2002, a number of complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates, including but not limited to Consumers which, while established, operated and regulated as a separate legal entity and publicly traded company, shares a parallel Board of Directors with CMS Energy. 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 running from May 2000 through March 2003. The cases were consolidated into a single lawsuit. The consolidated lawsuit generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, a motion was granted, dismissing Consumers and three of the individual defendants, but the court denied the motions to dismiss for CMS Energy and the 13 remaining individual defendants. Plaintiffs filed a motion for class certification on April 15, 2005 and an amended motion for class certification on June 20, 2005. The hearing on this motion is scheduled for February 28, 2006. On September 20, 2005, CMS Energy filed a motion for judgment on the pleadings, based on the Dura Pharmaceuticals decision issued by the United States Supreme Court. Plaintiffs filed their response on October 25, 2005, along with a so-called "cross-motion for partial summary judgment" seeking a determination that CMS Energy is liable for all damages proximately caused by its "culpable conduct." On November 29, 2005, the judge issued a decision denying both CMS Energy's motion for judgment on the pleadings and plaintiffs' cross-motion for partial summary judgment. CMS Energy and the individual defendants will defend themselves vigorously in this litigation but cannot predict its outcome.
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 2005, CMS Energy did not submit any matters to a vote of security holders.
CONSUMERS
During the fourth quarter of 2005, 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 (UNAUDITED), which is incorporated by reference herein. At February 22, 2006, the number of registered holders of CMS Energy Common Stock totaled 54,670, based upon the number of record holders. 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 2005, Consumers paid $118 million, $49 million, $40 million and $70 million in cash dividends, respectively, on its common stock. In February, May, August and November 2004, Consumers paid $77 million, $27 million, $82 million and $4 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)
2005 CONSOLIDATED FINANCIAL STATEMENTS
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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 years ended December 31, 2005 and 2004. These partnerships had third party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004.
(b) Effective December 31, 2003, Trust Preferred Securities are classified on 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 operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international diversified energy businesses including independent power production, electric distribution, and natural gas transmission, storage, and processing. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises.
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,
- energy commodity prices,
- interest rates, and
- our debt credit rating.
During the past two years, our business strategy has involved improving our balance sheet and maintaining focus on our core strength: utility operations 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 retain. Although most of our asset sales program is complete, we still may sell certain remaining businesses or assets as opportunities arise.
In 2005, we continued our focus on utility operations and meeting customer commitments. We also enhanced the financial returns of our Enterprises businesses by taking full advantage of the American Jobs Creation Act. In 2005, we repatriated $377 million from overseas to the U.S. under the provisions of this law at a 5.25 percent federal income tax rate. Nearly all of those dollars have been invested in Consumers.
Further, 2005 was the third year of our five-year plan to reduce parent debt. In 2005, we retired higher-interest rate consolidated debt and other obligations through the use of proceeds from the issuance of $275 million of CMS Energy senior notes and $875 million of Consumers' FMB. We also issued 23 million shares of common stock and invested $700 million in Consumers in 2005. In January 2006, we invested an additional $100 million in Consumers and in February 2006, Consumers extinguished, through a legal defeasance, $129 million of 9 percent related party notes.
Despite this progress, working capital and cash flow continue to be a challenge for us. Natural gas prices continue to increase substantially. Although our natural gas purchases are recoverable from our utility customers, as gas prices increase, the amount we pay for natural gas will require additional liquidity due to the lag in cost recoveries.
In addition to causing working capital issues for us, rising natural gas prices caused the MCV Partnership to reevaluate the economics of operating the MCV Facility and to determine that an impairment charge of $1.159 billion was required in September 2005. As a result, our 2005 net income was reduced by $369 million, after accounting for minority interest and tax effects. We further reduced our 2005 net income by $16 million by
CMS-3
impairing certain other assets on our Consolidated Balance Sheets related to the MCV Partnership. For additional details regarding the impairment, see Note 2, Asset Impairment Charges, Sales, and Discontinued Operations.
Projected future gas prices continue to threaten the continuing viability of the MCV Facility. We are evaluating various alternatives in order to develop a new long-term strategy with respect to the MCV Facility. The MCV Partnership is working aggressively to reduce costs, improve operations, and enhance cash flows. However, continued high gas prices could result in a further impairment of our ownership interests in the MCV Partnership and the FMLP.
Going forward, our strategy will continue to focus on:
- managing cash flow issues caused by rising gas prices,
- reducing parent company debt,
- maintaining and growing earnings, and
- positioning us to make investments that complement our strengths.
As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been further hampered by recent negative developments in Michigan's automotive industry and limited growth in the non-automotive and health services sectors of our economy.
These negative effects will be offset somewhat by the reduction we are experiencing in ROA load in our service territory. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of our total distribution load. It is, however, difficult to predict future ROA customer trends.
Finally, successful execution of our strategy will require continuing earnings and cash flow contributions from our Enterprises businesses.
FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-K and other written and oral statements that we make contain forward-looking statements as defined in Rule 3b-6 under the Securities Exchange Act of 1934, as amended, Rule 175 under the Securities Act of 1933, as amended, and relevant legal decisions. Our intention with the use of such words as "may," "could," "anticipates," "believes," "estimates," "expects," "intends," "plans," and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict and/or control:
- 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, including availability of financing to CMS Energy, Consumers, or any of their affiliates, and the energy industry,
- market perception of the energy industry, CMS Energy, Consumers, or any of their affiliates,
- credit ratings of CMS Energy, Consumers, or any of their affiliates,
- currency fluctuations, transfer restrictions, and exchange controls,
- 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,
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- adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions, including but not limited to Bay Harbor,
- potentially adverse regulatory treatment and/or regulatory lag concerning a number of significant questions presently before the MPSC including:
- recovery of Clean Air Act 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,
- adequate and timely recovery of additional electric and gas rate-based investments,
- adequate and timely recovery of higher MISO energy costs, and
- recovery of future Stranded Costs incurred due to customers choosing alternative energy suppliers,
- the impact of adverse natural gas prices on the MCV Partnership and FMLP investments, regulatory decisions that limit recovery of capacity and fixed energy payments, and our ability to develop a new long-term strategy with respect to the MCV Facility,
- federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of the market-based sales authorizations in wholesale power markets without price restrictions,
- energy markets, including availability of capacity and the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity and certain related products due to lower or higher demand, shortages, transportation problems, or other developments,
- our ability to collect accounts receivable from our gas customers due to high natural gas prices,
- 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 certain electric energy contracts at CMS ERM as derivatives,
- the GAAP requirement that we utilize mark-to-market accounting on certain energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods and could add to earnings volatility,
- the effect on our electric utility of the direct and indirect impacts of the continued economic downturn experienced by our automotive and automotive parts manufacturing customers,
- potential disruption, expropriation or interruption of facilities or operations due to accidents, war, terrorism, or changing political conditions and the ability to obtain or maintain insurance coverage for such events,
- 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,
- changes in tax laws or new IRS interpretations of existing tax laws,
- outcome, cost, and other effects of legal and administrative proceedings, settlements, investigations and claims, including particularly claims, damages, and fines resulting from round-trip trading and inaccurate
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commodity price reporting, including investigations by the DOJ regarding round-trip trading and price reporting,
- limitations on our ability to control the development or operation of projects in which our subsidiaries have a minority interest,
- disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance and performance bonds,
- the efficient sale of non-strategic or under-performing domestic or international assets and discontinuation of certain operations,
- other business or investment considerations that may be disclosed from time to time in CMS Energy's or Consumers' SEC filings, or in other publicly issued written documents, and
- other uncertainties that are difficult to predict, and many of which are beyond our control.
For additional information regarding these and other uncertainties, see Item 1A. Risk Factors, and Note 3, Contingencies.
RESULTS OF OPERATIONS
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
For 2005, our net loss available to common stockholders was $94 million compared to net income available to common stockholders of $110 million for 2004. Our losses in 2005 reflect a substantial asset impairment charge taken at the MCV Partnership and significant cost increases at our electric and gas utilities. These negative factors were offset partially by improvements in our non-regulated business earnings and substantial reductions in interest expense and income tax expense.
Specific changes to net income (loss) available to common stockholders for 2005 versus 2004 are:
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For 2004, our net income available to common stockholders was $110 million compared to a net loss available to common stockholders of $44 million for 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 the American Jobs Creation Act. 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 changes to net income (loss) available to common stockholders for 2004 versus 2003 are:
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ELECTRIC UTILITY RESULTS OF OPERATIONS
ELECTRIC DELIVERIES: For 2005, electric deliveries to end-use customers increased 1.3 billion kWh or 3.4 percent versus 2004. The corresponding increase in electric delivery revenue was due to increased sales to residential customers, reflecting warmer summer weather and increased surcharge revenue from all customers.
On July 1, 2004, Consumers started collecting a surcharge to recover costs incurred in the transition to customer choice. This surcharge increased electric delivery revenue by $13 million in 2005 versus 2004. Surcharge revenue related to the recovery of security costs and stranded costs increased electric delivery revenue by an additional $10 million in 2005 versus 2004.
For 2004, electric deliveries to end-use customers increased 0.1 billion kWh or 0.4 percent versus 2003. Despite the increase in electric deliveries, electric delivery revenue decreased due to the milder summer temperatures' negative impact on 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 in 2004 versus 2003.
POWER SUPPLY COSTS AND RELATED REVENUE: Our recovery of power supply costs was capped for our residential customers until January 1, 2006. For 2005, our underrecovery of power costs allocated to these capped
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customers increased by $76 million versus 2004. Power supply-related costs increased in 2005 primarily due to higher coal costs and higher purchased power costs due to higher weather-driven sales.
Partially offsetting these underrecoveries were benefits from the deferral of transmission and nitrogen oxide allowance expenditures related to our capped customers. To the extent these costs were not fully recoverable due to the application of rate caps, we deferred these costs for recovery under Public Act 141. In December 2005, the MPSC approved the recovery of these costs. For additional details, see "Electric Utility Business Uncertainties -- Competition and Regulatory Restructuring" within this MD&A. For 2005, deferrals of these costs increased by $30 million versus 2004.
For 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.
OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: For 2005, other operating expenses increased $139 million, other income increased $4 million, and non-commodity revenue increased $4 million versus 2004.
The increase in other operating expenses reflects higher depreciation and amortization expense, higher pension and benefit expense, and higher underrecovery expense related to the MCV PPA, offset partially by our direct savings from the RCP. Depreciation and amortization expense increased primarily due to a reduction in 2004 expense to reflect an MPSC order allowing recovery of $57 million of Stranded Costs. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005.
In 1992, a liability was established for estimated future underrecoveries of power supply costs under the MCV PPA. In 2004, a portion of the cash underrecoveries continued to reduce this liability until its depletion in December. In 2005, all cash underrecoveries were expensed directly to income. Consequently, the cost associated with the MCV PPA cash underrecoveries increased operating expense $30 million for 2005 versus 2004. Offsetting this increased operating expense were the savings from the RCP approved by the MPSC in January 2005.
The RCP allows us to dispatch the MCV Facility on the basis of natural gas prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas. The MCV Facility's fuel cost savings are first used to offset the cost of replacement power and fund a renewable energy program. Remaining savings are split between us and the MCV Partnership. Our direct savings were shared 50 percent with customers in 2005 and will be shared 70 percent thereafter. Our direct savings, after allocating an equal portion to customers, was $32 million for 2005.
For 2005, the increase in other income was primarily due to higher interest income on short-term cash investments versus 2004, offset partially by expenses associated with the early retirement of debt. The increase in non-commodity revenue was primarily due to higher transmission services revenue versus 2004.
For 2004, other operating expenses decreased $82 million, other income increased $12 million, and non-commodity revenue decreased $3 million versus 2003. Other operating expenses decreased due to reduced depreciation, pension, and benefit expenses. The decrease in depreciation expense reflects an MPSC order allowing recovery of $57 million of Stranded Costs incurred from 2002 to 2003. 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. 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.
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REGULATORY RETURN ON CAPITAL EXPENDITURES AND RELATED CAPITALIZED INTEREST: For 2005, the return on capital expenditures in excess of our depreciation base, net of related capitalized interest, decreased income by $30 million versus 2004. The decrease reflects the impact of the MPSC's December 2005 order authorizing recovery of and a return on our capital expenditures in excess of our depreciation base.
For 2004, the return on capital expenditures in excess of our depreciation base, net of related capitalized interest, increased income by $77 million versus 2003. The increase reflects a $72 million return on Clean Air Act costs incurred during the period June 2000 through December 2003 to reflect an interpretation of the Customer Choice Act by the MPSC in a rate order involving Detroit Edison.
GENERAL TAXES: For 2005, general taxes decreased primarily due to lower property tax expense. Lower property tax expense in 2005 reflects the use of revised tax tables by several of Consumers' taxing authorities and, separately, other property tax refunds.
For 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.
INTEREST CHARGES: For 2005, interest charges reflect a 31 basis point reduction in the average rate of interest on our debt. This benefit was offset partially by higher average debt levels versus 2004.
For 2004, interest charges reflect higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest on our debt versus 2003.
INCOME TAXES: For 2005, income taxes decreased primarily due to lower earnings versus 2004, offset partially by a $2 million increase to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders.
For 2004, income taxes increased primarily due to increased earnings from the electric utility versus 2003. The increase also reflects $2 million related to the tax treatment of items related to property, plant, and equipment as required by past MPSC orders. This increase was offset partially by the benefits received from Part D of the Medicare Prescription Drug, Improvement and Modernization Act, which was signed into law in December 2003.
GAS UTILITY RESULTS OF OPERATIONS
GAS DELIVERIES: For 2005, gas delivery revenues reflect lower deliveries to our customers versus 2004. Gas deliveries, including miscellaneous transportation to end-use customers, decreased 2.4 bcf or 0.7 percent.
For 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. The decrease in gas delivery revenues was offset partially
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by a $12 million increase in gas revenues associated with our annual 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 annual increase of $58 million through a two-year surcharge. As a result of these orders, gas revenues increased $28 million for 2005 versus 2004 and $28 million for 2004 versus 2003.
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUE AND OTHER INCOME: For 2005, income from gas wholesale and retail services and other gas revenue increased versus 2004. Other income increased primarily due to higher interest income on short-term cash investments, offset partially by expenses associated with the early retirement of debt, versus 2004.
For 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. Other income remained consistent with 2003.
OPERATION AND MAINTENANCE: For 2005, operation and maintenance expenses increased primarily due to increases in benefit costs and additional safety, reliability, and customer service expenses versus 2004. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005.
For 2004, operation and maintenance expenses decreased primarily due to reduced pension and benefit expense of $23 million versus 2003. 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 increased expenditures on safety, reliability, and customer service.
GENERAL TAXES: For 2005, general taxes decreased primarily due to lower property tax expense versus 2004. Lower property tax expense in 2005 reflects an increased use of revised tax tables by several of Consumers' taxing authorities, and separately, other property tax refunds. For 2004, general taxes increased due to the absence of an 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.
DEPRECIATION: For 2005, depreciation expense increased primarily due to higher plant in service versus 2004. For 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.
INTEREST CHARGES: For 2005, interest charges reflect a 31 basis point reduction in the average rate of interest on our debt and higher average debt levels versus 2004.
For 2004, interest charges reflect higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest on our debt versus 2003.
INCOME TAXES: For 2005, income taxes decreased due to lower earnings versus 2004. This decrease was offset by $5 million to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders, and the write-off of general business credits expected to expire in 2005.
For 2004, income taxes increased due to increased earnings versus 2003. This increase was offset by $7 million to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders, and by Part D of the Medicare Prescription Drug, Improvement and Modernization Act, which was signed into law in December 2003.
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ENTERPRISES RESULTS OF OPERATIONS
OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For 2005, these increases compared to 2004 were primarily due to the impact of increased customer demand on deliveries, fuel costs, and purchased power at South American subsidiaries and increased wholesale power sales and related costs at our Michigan generating plants. Also contributing to the increase in operating revenue were increased third-party gas sales and mark-to-market gains on gas contracts at CMS ERM.
For 2004, these decreases compared to 2003 were primarily due to the sale of wholesale gas and power contracts at CMS ERM offset partially by higher margins from South American subsidiaries.
FUEL COSTS MARK-TO-MARKET AT MCV: For 2005, the fuel costs mark-to-market adjustments of certain long-term gas contracts and financial hedges at the MCV Partnership increased operating earnings due to increased gas prices compared to reductions in 2004.
EARNINGS FROM EQUITY METHOD INVESTEES: For 2005, the increase in equity earnings compared to 2004 was primarily due to $10 million in earnings from Shuweihat, which achieved commercial operations in the third quarter of 2004, and a $5 million increase in earnings from GasAtacama, as it was able to import more natural gas from Argentina than in 2004. Also contributing to the increase were higher earnings at Neyveli of $6 million, primarily due to the settlement of a revenue dispute, and $4 million of other net increases in earnings. These increases were offset partially by the absence, in 2005, of $8 million in earnings from Goldfields, which we sold in August 2004 and lower earnings at Jorf Lasfar, primarily due to increases in coal related costs.
For 2004, the decrease in equity earnings compared to 2003 was primarily due to a $6 million reduction of earnings from Goldfields, which we sold in August 2004, and losses on the settlement of derivative contracts. These decreases were offset partially by $9 million in earnings from Shuweihat, which began limited operations during the fourth quarter of 2004.
GAIN ON SALE OF ASSETS: For 2005, gains on asset sales decreased compared to 2004. In 2005, we had gains on the sale of GVK and SLAP. In 2004, we had gains on the sale of Goldfields, the Bluewater Pipeline and land in Moapa, Nevada.
For 2004, gains on asset sales increased compared to 2003. In 2004, we had gains on the sale of Goldfields, the Bluewater Pipeline and land in Moapa, Nevada. In 2003, we had net losses on sales at CMS ERM, primarily due to the sale of their wholesale gas contracts, and a loss on the sale of Guardian pipeline, offset partially by a gain on the sale of land in Arcadia, Michigan.
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OPERATION AND MAINTENANCE: For 2005, the increase in operation and maintenance expenses compared to 2004 was primarily due to a loss on the termination of a prepaid gas contract, higher legal fees and the absence of an insurance settlement received in 2004. Also contributing to the increase were higher maintenance costs related to scheduled outages, new development costs and increased costs at South American subsidiaries related to higher electrical production.
For 2004, operation and maintenance expenses decreased compared to 2003 primarily as 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.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME, NET: For 2005, the net of general tax expense, depreciation, and other income increased operating income compared to 2004 primarily due to increased interest income, lower depreciation expense at the MCV Partnership due to impairment of property, plant, and equipment, lower accretion expense related to prepaid gas contracts, and the removal of a contingent liability related to Leonard Field.
For 2004, the net of general tax expense, depreciation, and other income decreased operating income compared to 2003 due to foreign exchange losses offset partially by lower depreciation due to the sale of non-essential assets at CMS ERM in 2003.
ASSET IMPAIRMENT CHARGES: For 2005, the increase in asset impairment charges is primarily due to the $1.159 billion impairment of property, plant, and equipment at the MCV Partnership, compared to the 2004 reduction in the fair value of Loy Yang and impairments related to the sale of our interests in GVK and SLAP.
For 2004, the increase in asset impairment charges is due to the reduction in the fair value of Loy Yang and impairments related to the sale of our interests in GVK and SLAP, compared to the 2003 impairments of our investment in CMS Electric and Gas' Venezuelan distribution utility and equity investments at CMS Generation.
ENVIRONMENTAL REMEDIATION: For 2005, we recorded an additional estimated environmental remediation cost of $40 million related to our involvement in Bay Harbor. In 2004, we recorded our initial estimate of $45 million.
FIXED CHARGES: For 2005, fixed charges decreased compared to 2004 primarily due to lower expense at the MCV Partnership as a result of lower debt levels due to principal payments.
For 2004, fixed charges decreased compared to 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. These decreases were offset partially by the payment of preferred dividends to the investor in our Michigan gas assets in 2004 and higher letter of credit fees.
MINORITY INTEREST: For 2005, net losses attributed to minority interest owners in our subsidiaries replaced net gains in 2004. The losses relate to the asset impairment charge to property, plant, and equipment at the MCV Partnership, offset partially by mark-to-market gains at the MCV Partnership.
For 2004, net gains attributed to minority interest owners in our subsidiaries were greater than the net gains in 2003, primarily due to net gains at CMS Electric and Gas replacing net losses in 2003. The 2003 net losses at CMS Electric and Gas relate to the impairment of our investment in CMS Electric and Gas' Venezuelan distribution utility.
RESULTS OF FASB INTERPRETATION NO. 46: We determined that we are the primary beneficiary of the MCV Partnership and the FMLP as defined by FASB Interpretation No. 46. As the primary beneficiary of these entities, we are required to include them as consolidated subsidiaries in the results of operations beginning in 2004. Prior to 2004, our portion of the net earnings or losses from the MCV Partnership and the FMLP was included in the results of operations as Earnings from equity method investees. For comparability purposes, only the change in net earnings for these entities is presented for 2004 versus 2003.
For 2004, earnings from the MCV Partnership and the FMLP decreased compared to 2003 primarily due to mark-to-market losses related to gas contracts and increased fuel and dispatch costs, primarily at the MCV Partnership. These decreases were offset partially by dispatch and variable energy rate variance revenue.
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INCOME TAXES: For 2005, the decrease in income tax expense compared to 2004 reflects lower earnings in 2005 due primarily to the impairment of property, plant, and equipment at the MCV Partnership and income tax benefits related to the American Jobs Creation Act of 2004.
For 2004, the decrease in income taxes compared to 2003 is primarily due to the foreign earnings repatriation tax benefit arising from the American Jobs Creation Act of 2004 and a decrease in tax reserves.
CORPORATE INTEREST AND OTHER NET EXPENSES
For 2005, corporate interest and other net expenses were $167 million, a decrease of $30 million compared to the same period in 2004. The decrease reflects lower interest expense due to lower average debt levels and a reduction in the average rate of interest. Also contributing to the reduction in expenses were lower debt retirement charges and an increase in corporate income tax benefits. The decrease was offset partially by increased legal fees.
For 2004, corporate interest and other net expenses were $197 million, a decrease of $59 million compared to the same period in 2003. The decrease reflects lower interest expense due to lower average debt levels and a reduction in the average rate of interest. Also contributing to the decrease was a reduction in debt retirement charges, and the absence in 2004 of a deferred tax asset valuation reserve established in 2003. The decrease was offset partially by an increase in the declaration and payment of CMS Energy preferred dividends and an increase in general taxes primarily due to the absence of MSBT refunds received in 2003.
DISCONTINUED OPERATIONS: For 2005, our net income from Discontinued Operations was $14 million, an increase of $18 million compared to the same period in 2004. Income from 2005 primarily reflects an arbitration award related to the 2003 sale of Marysville and a reduction in contingent liabilities due to favorable results from litigation involving previously sold businesses. The net loss for 2004 was primarily due to income tax adjustments, offset partially by gains on asset sales. Income from 2003 primarily reflects 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, Asset Impairment Charges, Sales, and Discontinued Operations.
ACCOUNTING CHANGES: In 2004, we recorded a $2 million loss for the cumulative effect of a change in accounting principle. The loss was the result of a change in the measurement date on our benefit plans. For additional details, see Note 7, Retirement Benefits.
In the first quarter of 2003, a $24 million loss for the cumulative effect of changes in accounting principle was recognized, 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 contingencies and long-lived assets 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 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. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, and contingencies. For example, we estimate the rate of return on plan assets and the cost of future health-care benefits to determine our annual pension and other postretirement benefit costs. 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.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that arise in the ordinary course of our business. We record a liability for contingencies based upon our assessment that a loss is probable and the amount of loss can be reasonably estimated. 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. Significant contingencies include our pending class actions arising out of round-trip trading and gas price reporting, our electric and gas environmental estimates, and our indemnity and environmental remediation obligations at Bay Harbor.
The amount of income taxes we pay is subject to ongoing audits by federal, state, and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have 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.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. We periodically perform tests of impairment if certain conditions that are other than temporary exist that may indicate the carrying value may not be recoverable. Of our total assets, recorded at $16.020 billion at December 31, 2005, 53 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.
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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. If the fair value is less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded.
Our assessments of fair value using these valuation methodologies represent our best estimates at the time of the reviews and are consistent with our internal planning. The estimates we use can change over time, which could have a material impact on our financial statements.
For additional details on asset impairments, see Note 2, Asset Impairment Charges, Sales, and Discontinued Operations.
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity.
For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate they will require that such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. At December 31, 2005, we had $1.800 billion recorded as regulatory assets and $1.753 billion recorded as regulatory liabilities.
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. These criteria are complex and significant judgment is often required in applying the criteria to specific contracts. If a contract is a derivative, it is recorded on the balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. For additional details on accounting for derivatives, see Note 6, Financial and Derivative Instruments.
To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we must use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. Changes in forward prices or volatilities could significantly change the calculated fair value of our derivative contracts. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of counterparties.
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The following table summarizes the interest rate and volatility rate assumptions we used to value these contracts at December 31, 2005:
The types of contracts we typically classify as derivative instruments are interest rate swaps, gas supply options, certain long-term gas contracts, gas fuel futures and swaps, certain gas and electric forward contracts, electric and gas options, electric swaps, and foreign currency exchange contracts. The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:
- they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MW of electricity or bcf of natural gas),
- they qualify for the normal purchases and sales exception, or
- there is not an active market for the commodity.
Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. Similarly, certain of our electric capacity and energy contracts are not derivatives due to the lack of an active energy market in Michigan. If active markets for these commodities develop in the future, some of these contracts may qualify as derivatives. For our coal purchase contracts, the resulting mark-to-market impact on earnings could be material. For our electric capacity and energy contracts, we believe that we would be able to apply the normal purchases and sales exception to the majority of these contracts (including the MCV PPA) and, therefore, would not be required to mark these contracts to market.
Establishment of the Midwest Energy Market: The MISO began operating the Midwest Energy Market on April 1, 2005. By operating the Midwest Energy Market, the MISO centrally dispatches electricity and transmission service throughout much of the Midwest and provides day-ahead and real-time energy market information. At this time, we believe that the establishment of this market does not represent the development of an active energy market in Michigan, as defined by SFAS No. 133. However, as the Midwest Energy Market matures, we will continue to monitor its activity level and evaluate if an active energy market may exist in Michigan.
Implementation of the RCP: As a result of implementing the RCP in January 2005, a significant portion of the MCV Partnership's long-term gas contracts no longer qualify as normal purchases because the gas will not be used to generate electricity or steam. Accordingly, these contracts are accounted for as derivatives, with changes in fair value recorded in earnings each quarter. Additionally, certain of the MCV Partnership's natural gas futures and swap contracts, which are used to hedge variable-priced long-term gas contracts, no longer qualify for cash flow hedge accounting and we record any changes in their fair value in earnings each quarter. As a result of recording the changes in fair value of these long-term gas contracts and the related futures and swaps to earnings, the MCV Partnership has recognized the following gains and losses in 2005:
These gains and losses, shown before consideration of tax effects and minority interest, are included in the total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income (Loss). Because of the volatility of the natural gas market, the MCV Partnership expects future earnings volatility on both the long-term
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gas contracts and the futures and swap contracts, since gains and losses will be recorded each quarter. As a result of mark-to-market gains, we have recorded derivative assets totaling $256 million associated with the fair value of these contracts on our Consolidated Balance Sheets. We expect almost all of these assets to reverse through earnings during 2006 and 2007 as the gas is purchased and the futures and swaps settle, with the remainder reversing between 2008 and 2011. Due to the impairment of the MCV Facility, the equity held by the minority interest owners of the MCV Partnership has decreased significantly. Since we have the controlling financial interest in the MCV Partnership, we will assume 100 percent of future losses recognized from the reversal of these assets, not just our proportionate share.
CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts as a part of activities considered to be an integral part of CMS Energy's ongoing operations. CMS ERM holds certain contracts for the future purchase and sale of electricity and natural gas that will result in physical delivery of the commodity at contractual prices. These forward contracts are generally long-term in nature and are classified as non-trading. CMS ERM also uses various financial instruments, including swaps, options, and futures, to manage commodity price risks associated with its forward purchase and sale contracts and with generation assets owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading activities.
In accordance with SFAS No. 133, non-trading and trading contracts that qualify as derivatives are recorded at fair value on our Consolidated Balance Sheets. The resulting assets and liabilities are marked to market each quarter, and the changes in fair value are recorded in earnings. For trading contracts, these gains and losses are recorded net in accordance with EITF Issue No. 02-03. Contracts that do not meet the definition of a derivative are accounted for as executory contracts (that is, on an accrual basis).
We include the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The following tables provide a summary of these contracts at December 31, 2005:
- ------------------------- (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 present value and credit reserves.
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MARKET RISK INFORMATION: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, currency exchange rates, and equity security prices. We may use various contracts to manage these risks, including swaps, options, futures, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of both:
- an executive oversight committee consisting of senior management representatives, and
- a risk committee consisting of business unit managers.
Our intention is that any increases or decreases in the value of these contracts will be offset by an opposite change in the value of the item at risk.
These contracts contain credit risk, which is the risk that counterparties, primarily financial institutions and energy marketers, will fail to perform their contractual obligations. We reduce this risk through established credit policies, which include performing financial credit reviews of our counterparties. We determine our counterparties' credit quality using a number of factors, including credit ratings, disclosed financial condition, and collateral requirements. If terms permit, we use standard agreements that allow us to net positive and negative exposures associated with the same counterparty. Based on these policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or earnings as a result of counterparty nonperformance.
The following risk sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical unfavorable change in market rates or prices of 10 percent. Changes in excess of the amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift used for the analyses.
Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital.
Interest Rate Risk Sensitivity Analysis (assuming an unfavorable change in market interest rates of 10 percent):
- ------------------------- (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: Operating in the energy industry, we are exposed to commodity price risk, which arises from fluctuations in the price of electricity, natural gas, coal, and other commodities. Commodity prices are influenced by a number of factors, including weather, changes in supply and demand, and liquidity of commodity markets. In order to manage commodity price risk, we enter into various non-trading derivative contracts, such as
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gas supply call and put options, forward purchase and sale contracts for electricity and natural gas, long-term gas contracts, gas futures, and gas swaps. We also enter into trading derivative contracts, including electric and gas options and swaps, and gas futures. For additional details on these contracts, see Note 6, Financial and Derivative Instruments.
Commodity Price Risk Sensitivity Analysis (assuming an unfavorable change in market prices of 10 percent):
- ------------------------- (a) The increased potential reduction in fair value for the MCV Partnership's long-term gas contracts is due to the increased number of contracts accounted for as derivatives as a result of the RCP.
Currency Exchange Risk: Because of our investments in foreign operations and equity interests in various international projects, we are exposed to currency exchange risk. In order to protect the company from the risk associated with unfavorable changes in currency exchange rates, which could materially affect cash flow, we may use risk mitigating instruments. These instruments, such as forward exchange contracts, allow us to hedge currency exchange rates. At December 31, 2005, 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 (assuming an unfavorable change in market prices of 10 percent):
Consumers maintains trust funds, as required by the NRC, for the purpose of funding certain costs of nuclear plant decommissioning. At December 31, 2005 and 2004, 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 our earnings or cash flows.
For additional details on market risk and derivative activities, see Note 6, Financial and Derivative Instruments.
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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. On September 1, 2005, we implemented the DCCP.
The DCCP provides an employer cash contribution of 5 percent of base pay to the existing Employees' Savings Plan. No employee contribution is required in order to receive the plan's employer contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. We use SFAS No. 87 to account for pension costs.
401(k): We resumed the employer's match in CMS Energy Common Stock in our 401(k) Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages.
OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. We use SFAS No. 106 to account for other postretirement benefit costs.
Liabilities for both pension and OPEB are recorded on the balance sheet at the present value of their future obligations, net of any plan assets. The calculation of the liabilities and associated expenses requires the expertise of actuaries. Many assumptions are made, including:
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
Any change in these assumptions can change significantly the liability and associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
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 8.50 percent to 8.25 percent) would increase estimated pension cost for 2006 by $3 million. Lowering the discount rate by 0.25 percent (from 5.75 percent to 5.50 percent) would increase estimated pension cost for 2006 by $1 million.
For additional details on postretirement benefits, see Note 7, Retirement Benefits.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, as clarified by FASB Interpretation No. 47, requires companies to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal
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obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. For Consumers, as required by SFAS No. 71, we account for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions, such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. In addition, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates. For additional details 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, or remove from service, our Big Rock and Palisades nuclear plants. Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent landscape,
- all contaminated equipment and material will be removed and disposed of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning 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.
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. 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 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. At this time, we cannot determine what impact a license renewal for the Palisades plant will have on decommissioning costs or the adequacy of funding. For additional details, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Plant Decommissioning" and "Nuclear Matters," and Note 8, Asset Retirement Obligations.
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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. In 2005, the market price for natural gas increased substantially. Although our prudent natural gas purchases are recoverable from our customers, as gas prices increase, the amount paid for natural gas stored as inventory requires additional liquidity due to the timing of the cost recoveries. We have credit agreements with our commodity suppliers and those agreements contain terms that have resulted in margin calls. Additional margin calls or other credit support may be required if agency ratings are lowered or if market conditions remain unfavorable relative to our obligations to those parties.
Our current financial plan includes controlling operating expenses and capital expenditures and evaluating market conditions for financing opportunities. Due to the adverse impact of the MCV Partnership asset impairment charge recorded in September 2005, Consumers' ability to issue FMB as primary obligations or as collateral for financing is expected to be limited to $298 million through September 30, 2006. After September 30, 2006, Consumers' ability to issue FMB in excess of $298 million is based on achieving a two-times FMB interest coverage ratio.
We believe the following items will be sufficient to meet our liquidity needs:
- our current level of cash and revolving credit facilities,
- our ability to access junior secured and unsecured borrowing capacity in the capital markets, and
- our anticipated cash flows from operating and investing activities.
We have not made a specific determination concerning the reinstatement of common stock dividends. The Board of Directors may reconsider or revise its dividend policy based upon certain conditions, including our results of operations, financial condition, and capital requirements, as well as other relevant factors.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2005, $1.045 billion consolidated cash was on hand, which includes $198 million of restricted cash and restricted short-term investments and $367 million from the entities consolidated pursuant to FASB Interpretation No. 46. For additional details, see Note 16, Consolidation of Variable Interest Entities.
Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For the year ended December 31, 2005, Consumers paid $277 million in common stock dividends and Enterprises paid $297 million in common stock dividends and other distributions to CMS Energy.
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SUMMARY OF CASH FLOWS:
OPERATING ACTIVITIES:
2005: Net cash provided by operating activities increased $248 million versus the same period in 2004. Included in cash provided by operations is a tentative insurance settlement, a decrease in prepaid gas margin call costs, the positive effect of rising gas prices on accounts payable and MCV gas supplier funds on deposit, and other timing differences. These increases were offset partially by the negative effect of rising gas prices on accounts receivable and inventories.
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.
INVESTING ACTIVITIES:
2005: Net cash used in investing activities increased $149 million versus the same period in 2004 primarily due to an increase in restricted cash and restricted short-term investments of $296 million combined with a decrease in proceeds from asset sales of $158 million. These changes were offset partially by a net increase in short-term investment proceeds of $218 million and a decrease in investments in unconsolidated subsidiaries of $71 million. The increase in restricted cash and restricted short-term investments was due to a deposit made with a trustee for extinguishing the current portion of long-term debt -- related parties.
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.
FINANCING ACTIVITIES:
2005: Net cash provided by financing activities increased $117 million versus the same period in 2004 primarily due to a decrease in debt retirements of $122 million.
2004: Net cash used in financing activities increased $272 million primarily due to a decrease of $232 million in net proceeds from borrowings.
For additional details on long-term debt activity, see Note 4, Financings and Capitalization.
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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 2006.
Long-Term Debt: The amounts in the preceding table represent the principal amounts due on outstanding debt obligations, current and long-term, at December 31, 2005. For additional details on long-term debt, see Note 4, Financings and Capitalization.
Interest payments on long-term debt: The amounts in the preceding table 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, 2005.
Capital and finance leases: The amounts in the preceding table represent the minimum lease payments payable under our capital and finance leases. They are comprised mainly of the leased portion of the MCV Facility, leased service vehicles, and leased office furniture.
Interest payments on capital and finance leases: The amounts in the preceding table represent imputed interest in the capital leases and currently scheduled interest payments on the finance leases.
Operating Leases: The amounts in the preceding table 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: The amounts in the preceding table represent long-term contracts for purchase of commodities and services. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include:
- natural gas,
- electricity, and
- coal and associated transportation.
Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $8 million per month during 2006. 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."
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Long-term Service Agreements: The amounts in the preceding table represent obligations of the MCV Partnership, primarily the cost of the current MCV Facility maintenance service agreements and cost of spare parts.
REVOLVING CREDIT FACILITIES: At December 31, 2005, CMS Energy had $204 million available, Consumers had $464 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 various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, letters of credit, surety bonds, and financial and performance guarantees.
We enter into agreements containing indemnifications standard in the industry and indemnifications specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually agreements to reimburse other companies if those companies incur losses due to third-party claims or breach of contract terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a third party. Letters of credit substitute the bank's credit for ours and reduce credit risk for the third-party beneficiary. We monitor these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. For additional details on these and other guarantee arrangements, see Note 3, Contingencies, "Other Contingencies -- FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others."
Non-recourse Debt: Our share of unconsolidated debt associated with partnerships and joint ventures in which we have a minority interest is non-recourse and totals $1.271 billion at December 31, 2005. The timing of the payments of non-recourse debt only affects the cash flow and liquidity of the partnerships and joint ventures. For summarized financial information of our investments in certain partnerships and joint ventures, see Note 13, Equity Method Investments.
Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for securitized financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see Note 4, Financings and Capitalization.
DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4, Financings and Capitalization.
DEBT CREDIT RATING: In November 2005, S&P placed CMS Energy's and Consumers' debt credit ratings on CreditWatch with negative implications. In January 2006, S&P removed the ratings from CreditWatch with negative implications and affirmed CMS Energy's and Consumers' debt credit ratings with a stable outlook.
BOND REPURCHASE: In January and through February 23, 2006, we have purchased in the open market or contracted to purchase approximately $41 million principal amount of our 9.875 percent senior notes due 2007.
CAPITAL EXPENDITURES: We estimate that we will make the following capital expenditures, including new lease commitments, during 2006 through 2008. We prepare these estimates for planning purposes and may revise them.
- ------------------------- (a) These amounts include estimates for capital expenditures that may be required by recent revisions to the Clean Air Act's national air quality standards.
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(b) These amounts include estimates for capital expenditures related to information technology projects, facility improvements, and vehicle leasing.
OUTLOOK
CORPORATE OUTLOOK
Over the next few years, our business strategy will focus on reducing parent company debt, growing earnings, and positioning us to make new investments that complement our strengths.
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 retain. Although most of our asset sales program is complete, we still may sell certain remaining businesses or assets as opportunities arise. The percentage of our future earnings relating to our equity method investments may increase and our total future earnings may depend more significantly upon the performance of those investments. For summarized financial information of our equity method investments, see Note 13, Equity Method Investments.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Summer 2005 temperatures were higher than historical averages, leading to increased demand from electric customers. As a result, growth in electric deliveries in 2005, excluding transactions with other wholesale market participants and other utilities, was more than three percent. In 2006, we project electric deliveries to be about flat compared to the levels experienced in 2005. This short-term outlook for 2006 assumes a recovering economy 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. However, such growth is dependent on a modestly growing customer base and recovery of the Michigan 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 or contraction of manufacturing facilities.
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 requested an annual increase in revenues of approximately $320 million, which we revised in August 2005 to approximately $197 million. The primary reasons for our electric rate case were increased system maintenance and improvement costs, Clean Air Act-related expenditures, and employee pension costs. In December 2005, the MPSC issued an order that allows a base rate increase in the annual amount of $86 million, establishes an 11.15 percent authorized return on equity, and recognizes the impacts on our projected equity investment (infusions and retained earnings) in 2006. The base rate increase includes a contribution of $27 million to Michigan's Low Income and Energy Efficiency Fund. Portions of the base rate increase are subject to refund if expenditures in certain categories are lower than assumed in establishing rates. New electric base rates became effective in mid-January 2006.
In January 2006, an intervenor in the electric rate case filed a petition with the MPSC to seek rehearing or clarification on certain issues addressed in the December 2005 order. In January 2006, we also filed a petition to seek rehearing or clarification on certain issues in the order. We cannot predict the outcome of these petitions.
ELECTRIC TRANSMISSION EXPENSES: In December 2005, the FERC issued an order that conditionally accepts an application from METC, which provides electric transmission service to us, to increase substantially the transmission rates it will charge us in 2006. We are attempting to recover these costs through our 2006 PSCR plan case. In December 2005, the MPSC issued an order that temporarily excludes a portion of the increased costs from our PSCR charge, which began in January 2006. The PSCR process allows recovery of all reasonable and prudent power supply costs. However, we cannot predict when full recovery of these transmission costs will commence. To the extent that we incur and are unable to collect these increased costs in a timely manner, our
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cash flows from electric utility operations will be affected negatively. For additional details, see Note 3, Contingencies, "Consumers' Electric Utility Rate Matters -- Power Supply Costs."
ELECTRIC RESERVE MARGIN: 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 establish a reserve margin target to address various scenarios and contingencies so that the probability of interrupting service to retail customers because of a supply shortage is no greater than an industry-recognized standard. However, even with the reserve margin target, additional spot purchases may be required during periods when electric prices are high.
We are planning currently for a reserve margin of approximately 11 percent for summer 2006, or supply resources equal to 111 percent of projected firm summer peak load. Of the 2006 supply resources target of 111 percent, we expect to meet approximately 96 percent from our electric generating plants and long-term power purchase contracts, and approximately 15 percent from other contractual arrangements. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2006 through 2010. As a result, we have recognized an asset of $6 million for unexpired capacity and energy contracts at December 31, 2005.
ELECTRIC CAPACITY NEEDS FORUM: In January 2006, the MPSC Staff issued a report on future electric capacity needs in the state of Michigan. The report indicated that existing generation resources are adequate in the short term, but could be insufficient to maintain reliability standards by 2009. The report also indicated that new baseload electric generation may be needed by 2011. The MPSC Staff recommended an approval and bid process for new power plants. To address revenue stability risks, the Staff also recommended a special reliability charge a utility would assess on all electric distribution customers. In January 2006, the MPSC solicited comments on the capacity needs report and announced a public hearing for March 2006. We will continue to participate in this forum as the MPSC develops ratemaking policy to address future electric capacity needs.
INDUSTRIAL REVENUE OUTLOOK: Our electric utility customer base includes a mix of residential, commercial, and diversified industrial customers, the largest segment of which is the automotive industry. In October 2005, Delphi Corporation (Delphi) filed for Chapter 11 bankruptcy protection. Delphi is the nation's largest automotive supplier headquartered in Troy, Michigan, and is a large industrial customer of Consumers. Our electric utility operations are not dependent upon a single customer, and we do not believe that this event will have a material adverse effect on our financial condition. In November 2005, General Motors Corporation, also a large industrial customer of Consumers, announced plans to reduce manufacturing capacity, including certain operations in Michigan. We cannot predict the impact of these restructuring plans or possible future actions by other industrial customers. Continued degradation of the industrial customer base would have a negative impact on electric utility revenues.
ENERGY MARKET DEVELOPMENT: The MISO began operating the Midwest Energy Market on April 1, 2005. The Midwest Energy Market includes a day-ahead and real-time energy market and centralized generation dispatch for market participants. We are a participant in this energy market. The intention of this market is to meet load requirements in the region reliably and efficiently, to improve management of congestion on the grid, and to centralize dispatch of generation throughout the region. The MISO is now responsible for the reliability and economic dispatch in the entire MISO area, which covers parts of 15 states and Manitoba, including our service territory.
The settlement of charges for each operating day of the Midwest Energy Market invokes the issuance of multiple settlement statements over a 155-day period through March 2006 and a 365-day period beginning in April 2006. This extended settlement period is designed to allow for adjustments associated with the receipt of complete billing information and other adjustments. When adjustments are necessary, the MISO bills market participants on a retroactive basis, covering several months, which may result in either a positive or a negative billing adjustment. We record an expense accrual for future adjustments based on historical experience.
COAL DELIVERY DISRUPTIONS: In May 2005, western coal rail carriers experienced derailments and significant service disruptions that affected all shippers of western coal from Wyoming mines as well as coal producers from
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May 2005 through June 2005. Under contractual Force Majeure provisions, the coal tonnage not delivered during this period was not made up. Although we experienced some impact on coal shipments during the rail repair period, our inventories have remained within historical levels during the winter period, though at lower levels than planned before the disruptions occurred. Based on our present delivery experience, projections, and inventory, we believe we will continue to have adequate coal supply to allow for normal dispatch of our coal-fired generating units.
RENEWABLE RESOURCES PROGRAM: In January 2005, in collaboration with the MPSC, we established a RRP. Under the RRP, we purchase energy from approved renewable sources, which include solar, wind, geothermal, biomass, and hydroelectric suppliers. In August 2005, we secured long-term renewable energy supply contracts that the MPSC approved in October 2005. Customers are able to participate in the RRP in accordance with tariffs approved by the MPSC. The MPSC authorized recovery of above-market costs for the RRP by establishing a fund that consists of an annual contribution from savings generated by the RCP, a surcharge imposed by the MPSC on all customers, and contributions from customers that choose to participate in the RRP. In February 2005, the Attorney General filed appeals of the MPSC orders providing funding for the RRP in the Michigan Court of Appeals. In November 2005, the Michigan Court of Appeals issued an order that reversed the portion of the MPSC order that allows a surcharge imposed on all customers. The RRP will continue to be funded by savings generated by the RCP and by customers that participate in the program.
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 filed an appeal with the Michigan Supreme Court and, in October 2005, the Michigan Supreme Court agreed to review the lower court's decision. Consumers and other industry parties filed a brief in support of Detroit Edison's appeal. Unless overturned by the Michigan Supreme Court, the decision could encourage other municipalities to adopt similar ordinances, as has occurred or is under discussion in a few municipalities in our service territory. If incurred, we would seek recovery of these costs from our customers located in the municipality affected, 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.
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.
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 Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $815 million. The key assumptions in the capital expenditure estimate include:
- construction commodity prices, especially construction material and labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- 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 8.3 percent. As of December 2005, we had incurred $605 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $210 million of capital expenditures will be made in 2006 through 2011. These expenditures include installing selective catalytic control reduction technology at four of our coal-fired electric plants. In addition to modifying coal-fired electric plants,
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our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $10 million per year, which we expect to recover from our customers. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the coal-fired electric generating units emit nitrogen oxide. The expense is recovered from our customers through the PSCR process.
The EPA recently adopted a Clean Air Interstate Rule that requires additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. The rule involves a two-phase program to reduce emissions of sulfur dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule will require that we run our selective catalytic control technology units year-round beginning in 2009 and may require that we purchase additional nitrogen oxide allowances beginning in 2009.
In addition to the selective catalytic control technology installed to meet the nitrogen oxide standards, our current plan includes installation of flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to meet the Phase I reduction requirements of the Clean Air Interstate Rule, at costs similar to those to comply with the nitrogen oxide standards. We currently have a surplus of sulfur dioxide allowances, which were granted by the EPA and are accounted for as inventory. In January 2006, we sold some of our excess sulfur dioxide allowances for $61 million and recognized the proceeds as a regulatory liability.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric power plants by 2010 and further reductions by 2018. While the industry has not reached a consensus on the technical methods for curtailing mercury emissions, our capital and operating costs for mercury emissions reductions are expected to be significantly less than what was required for selective catalytic reduction technology used for nitrogen oxide compliance.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to certain aspects of EPA's Clean Air Mercury Rule, asserting that the rule is inadequate. The MDEQ has not indicated the direction that it will pursue to meet or exceed the EPA requirements through state rulemaking. We are actively participating in dialog with the MDEQ regarding potential paths for controlling mercury emissions and meeting the EPA requirements. In October 2005, the EPA announced it would reconsider certain aspects of the Clean Air Mercury Rule. We cannot predict the outcome of this proceeding.
Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any of these rules.
To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. We cannot estimate the potential effect of federal or state level greenhouse gas policy on our future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, we stay abreast of and engage in 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 2007. We currently are performing the required studies 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: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount
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represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of our total distribution load. It is difficult to predict future ROA customer trends.
Section 10d(4) Regulatory Assets: 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. Of the $628 million, $152 million relates to the cost of money. In June 2005, the ALJ issued a proposal for decision recommending the MPSC approve recovery of approximately $323 million in Section 10d(4) costs, which includes the cost of money through the period of collection. In December 2005, the MPSC issued an order that authorized us to recover the same costs recommended by the ALJ starting in January 2006. However, instead of collecting these costs evenly over five years, the order instructed us to collect 10 percent of the regulatory asset total in the first year, 15 percent in the second year, and 25 percent in the third, fourth, and fifth years. As a result, the total amount authorized for collection, including carrying costs, was $333 million. In January 2006, we filed a petition for rehearing with the MPSC that disputes the aspect of the order dealing with the timing of our collection of costs approved for recovery in this case. We cannot predict the outcome of this petition.
Stranded Costs: Prior MPSC orders adopted a mechanism pursuant to the Customer Choice Act to provide recovery of Stranded Costs that occur when customers leave our system to purchase electricity from alternative suppliers. In November 2005, we filed an application with the MPSC related to the determination of 2004 Stranded Costs. Applying the Stranded Cost methodology used in prior MPSC orders, we concluded that we experienced zero Stranded Costs in 2004.
Implementation Costs: In June 2005, the MPSC issued an order that authorizes us to recover costs from the implementation of the Customer Choice Act incurred during 2002 and 2003 totaling $6 million, plus the cost of money through the period of collection. We pursued authorization at the FERC for the MISO to reimburse us for Alliance RTO development costs. Included in this amount is $2 million that the MPSC did not approve as part of our 2002 implementation costs application. The FERC denied our request for reimbursement, and we appealed the FERC ruling at the United States Court of Appeals for the District of Columbia. In November 2005, the United States Court of Appeals for the District of Columbia denied our appeal.
Through and Out Rates: In December 2004, we began paying a transitional charge pursuant to a FERC order eliminating regional "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. Although the transitional charge ends in March 2006, there are hearings scheduled for May 2006 at the FERC to discuss these charges. The FERC hearings could result in refunds or additional transitional charges to us. We cannot predict the outcome of these hearings.
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."
OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES
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. We hold a 49 percent partnership interest in the MCV Partnership, and a 35 percent lessor interest in the MCV Facility.
Under the MCV 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. Natural gas prices have increased substantially in recent years and throughout 2005. In 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and recorded an impairment charge. If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected and could result in the MCV Partnership failing to meet its obligations under the sale and leaseback transactions and other contracts. For additional details on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges, Sales, and Discontinued Operations. We are evaluating various alternatives in order to develop a new long-term strategy with respect to the MCV Facility.
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Further, the cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity and fixed energy payments of $55 million in 2006 and $39 million in 2007. However, Consumers' direct savings from the RCP, after allocating a portion to customers, are used to offset our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse effect on the MCV Partnership's financial performance, 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 15, 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out clause, the MCV Partnership may have the right to terminate the MCV PPA. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 15, 2007 may affect negatively the financial performance of the MCV Partnership.
For additional details on the MCV Partnership, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration Venture."
NUCLEAR MATTERS:
Big Rock: Decommissioning of the site is nearing completion. Demolition of the last remaining plant structure, the containment building, and removal of remaining underground utilities and temporary office structures is expected to be completed by the summer of 2006. Final radiological surveys will then be completed including confirmatory surveys performed by the NRC to ensure that the site meets all requirements for free, unrestricted release in accordance with the NRC approved License Termination Plan (LTP) for the project. We anticipate NRC approval to return approximately 485 acres of the site, including the area formerly occupied by the nuclear plant, to a natural setting for unrestricted use by early 2007. We expect another area of approximately 105 acres encompassing the Big Rock Independent Spent Fuel Storage Installation (ISFSI), where eight casks loaded with spent fuel and other high-level radioactive material are stored, to be returned to a natural state within approximately two years from the date the DOE finishes removing the spent fuel from Big Rock also in accordance with the LTP.
Palisades: In August 2005, the NRC completed its performance review of the Palisades Nuclear Plant for the first half of the calendar year 2005. The NRC determined that Palisades was operated in a manner that preserved public health and safety and met all of the NRC's specific "cornerstone objectives." As of August 2005, 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 31, 2007.
The amount of spent nuclear fuel at Palisades exceeds the plant's temporary onsite wet storage pool capacity. We are using dry casks for temporary onsite dry storage to supplement the wet storage pool capacity. As of January 2006, we have loaded 29 dry casks with spent nuclear fuel.
Palisades' current license from the NRC expires in 2011. In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. Certain parties are seeking to intervene and have requested a hearing on the application. The NRC has stated that it expects to take 22-30 months to review a license renewal application. We expect a decision from the NRC in 2007.
Palisades, like other nuclear plants, has experienced cracking in reactor head nozzle penetrations. Repairs to two nozzles were made in 2004. We have authorized the purchase of a replacement reactor vessel closure head. The replacement head is being manufactured and is scheduled to be installed in 2007.
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In December 2005, we announced plans to sell the Palisades nuclear plant and enter into a long-term power purchase agreement with the new owner. We believe a sale is the best option for our company, as it will reduce risk and improve cash flow while retaining the benefits of the plant for customers.
The Palisades sale will use a competitive bid process, providing interested companies the option to bid on the plant, as well as the related decommissioning liabilities and trust funds assets, and spent nuclear fuel at Palisades and Big Rock. We expect to complete the sale in 2007.
For additional details on nuclear plant decommissioning at Big Rock and Palisades, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear Plant Decommissioning."
GAS UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to be relatively flat. Actual gas deliveries in future periods may be affected by:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- changes in gas commodity prices,
- Michigan economic conditions,
- the price of competing energy sources or fuels, and
- gas consumption per customer.
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 2005-2006. We started construction of Phase I of the pipeline in June 2005. Phase I of the project was completed and put in service in early December 2005. We anticipate completion of Phase II of the project in 2008.
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. In August 2005, the MPSC issued an order approving the application. Construction of the pipeline is expected to begin in mid-2006.
GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our future financial results and financial condition. These trends or uncertainties could have a material impact on revenues or income from gas operations.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 3, Contingencies, "Consumers' Gas Utility Contingencies -- Gas Environmental Matters."
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs for prudency in an annual reconciliation proceeding. For additional details on gas cost recovery, see Note 3, Contingencies, "Consumers' Gas Utility Rate Matters -- Gas Cost Recovery."
2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously ordered $34 million reduction in our depreciation expense,
- required us to undertake a study to determine why our plant removal costs are in excess of other regulated Michigan natural gas utilities, and
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- required us to file a study report with the MPSC Staff on or before December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.
We are also required to file our next gas depreciation case within 90 days after the MPSC issuance of a final order in the pending case related to ARO accounting. We expect an MPSC order in the first quarter of 2006.
If the depreciation case order is issued after the gas general rate case order, we proposed to incorporate its results into the gas general rates using a surcharge mechanism.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking a 12 percent authorized return on equity along with a $132 million annual increase in our gas delivery and transportation rates. The primary reasons for the request are recovery of new investments, carrying costs on natural gas inventory related to higher gas prices, system maintenance, employee benefits, and low-income assistance. If approved, the request would add approximately 5 percent to the typical residential customer's average monthly bill. The increase would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million. The MPSC Staff and intervenors filed interim rate relief testimony on October 31, 2005. In its testimony, the MPSC Staff recommended granting interim rate relief of $38 million. As of February 2006, the MPSC has not acted on our interim rate relief request.
On February 13, 2006, the MPSC Staff recommended granting final rate relief of $62 million. The MPSC Staff proposed that $17 million of this amount be contributed to a low income energy efficiency fund. The MPSC Staff also recommended reducing our return on common equity to 11.15 percent, from our current 11.4 percent.
EMERGENCY RULES REGARDING BILLING PRACTICES: On October 18, 2005, the MPSC issued an order adopting emergency rules for the winter heating period of November 1, 2005 through March 31, 2006. The rules address billing practices for retail customers of electric and gas utilities subject to the MPSC's jurisdiction. The emergency rules are designed to address the increase in heating costs this winter. They address billing cycles, fees, deposits, shutoffs, and collection of unpaid bills. The emergency rules will have an estimated $4 million negative effect on our collections and cash flow in 2006.
ENTERPRISES OUTLOOK
We plan to continue restructuring our Enterprises 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 not consistent with this focus.
Successful businesses, such as Taweelah and Shuweihat in the United Arab Emirates and Jorf Lasfar in Morocco, continue to make a valuable contribution. We continually evaluate opportunities to expand our investment in these businesses. We also evaluate new development opportunities outside of our current asset base to determine whether they fit within our business strategy. These and other investment opportunities for our enterprises segment would be considered for risk, rate of return, and consistency with our business strategy.
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 taxes or laws or in governmental or regulatory policies that could reduce significantly the tariffs charged and revenues recognized by certain foreign subsidiaries, or increase expenses,
- 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,
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- 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,
- changes in available gas supplies or Argentine government regulations that could restrict natural gas exports to our GasAtacama generating plant, and
- impact of indemnity and environmental remediation obligations at Bay Harbor.
SENECA operates an electric utility on Margarita Island, Venezuela under a Concession Agreement with the Venezuelan Ministry of Energy and Mines, now the Ministry of Energy and Petroleum (MEP). The Concession Agreement provides for semi-annual customer tariff adjustments for the effects of inflation and foreign exchange variations. The last tariff adjustment occurred in December 2003. It was less than the amount required by the Concession Agreement and no tariff increases have been granted since then. In July 2003, the MEP approved a fuel subsidy for SENECA to offset partially the effects of its lower tariff revenues. The fuel subsidy expired on December 31, 2004. SENECA has sent several letters to the MEP indicating that the economic circumstances that required the implementation of the fuel subsidy persist. In the letters, SENECA has informed the MEP that, unless it objects, SENECA will continue to apply the fuel subsidy as a credit against a portion of its fuel bills from its fuel supplier, Deltaven, a governmental body regulated by the MEP. SENECA has not received any response to the letters from the MEP; therefore, SENECA is taking the fuel subsidy as a credit against billings from Deltaven. Deltaven has continued to deliver fuel without interruption. We are informed that the government is considering whether to grant financial relief to SENECA pursuant to its Concession Agreement obligations. The outcome is uncertain since all alternatives are still being explored. If timely financial relief is not approved, the liquidity of SENECA and the value of our investment in SENECA would be impacted adversely.
OTHER OUTLOOK
MCV IMPAIRMENT ISSUES: Due to the impairment of the MCV Facility, the equity held by the minority interest owners of the MCV Partnership has decreased significantly. Since we have the controlling financial interest in the MCV Partnership, we will record 100 percent of future losses incurred at the MCV Partnership, not just our proportionate share.
The impairment of the MCV Facility, and any potential future impairment of the MCV Facility, will likely decrease the amount of equity investment recognized for ratemaking purposes in future electric and gas rate orders. Lower equity investment may result in a reduced revenue requirement. However, we cannot predict the outcome of any future rate cases, which may be lower or higher based on several factors, including the amount of equity investment and related risk. For additional information on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges, Sales, and Discontinued Operations.
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, securities class action lawsuits, a class action lawsuit alleging ERISA violations, and several lawsuits regarding alleged false natural gas price reporting and price manipulation. For additional details regarding this investigation and litigation, see Note 3, Contingencies.
PENSION REFORM: Both branches of Congress passed legislation aimed at reforming pension plans. The U.S. Senate passed The Pension Security and Transparency Act in November of 2005 and The House of Representatives passed the Pension Protection Act of 2005 in December of 2005. At the core of both bills are changes in the calculation of pension plan funding requirements effective for plan years beginning in 2007, with interest rate relief extended until then, and an increase in premiums paid to the Pension Benefit Guaranty Corporation (PBGC). The latter was addressed through the broader budget reconciliation bill, which raises the PBGC flat-rate premiums from $19 to $30 per participant per year beginning in 2006. Although the Senate and House bills are similar, they do contain a number of technical differences, including differences in the time period allowed for interest rate and asset smoothing, the interest rate used to calculate lump sum payments, and the criteria used to determine whether a plan is "at-risk," which requires higher contribution levels. The Senate and
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the House plan to work out the differences between the two bills in a joint conference. The timing, however, of a final pension reform bill is unknown. We are analyzing the impact of this legislation.
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
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 created a one-time opportunity to receive a tax benefit for U.S. corporations that reinvest, in the U.S., dividends received in a year (2005 for CMS Energy) from controlled foreign corporations. During 2005, we repatriated $377 million of foreign earnings that qualified for the tax benefit. The net effect of the repatriated earnings were tax benefits of $45 million in 2005 and $21 million in 2004, which were recorded in income from continuing operations.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS: This Interpretation became effective for us on December 31, 2005. It clarifies the term "conditional asset retirement obligation" as used in SFAS No. 143 and specifies that an obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Upon adoption of this Interpretation, we recorded $36 million of conditional asset retirement obligations relating to asbestos abatement. Implementation did not impact results of operations due to regulatory accounting. For additional details, see Note 8, Asset Retirement Obligations.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. Companies must expense this amount over the vesting period of the awards. This 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 including the timing of expense recognition for share-based awards with terms that accelerate vesting upon retirement. As a result of these clarifications, future compensation costs for share-based awards with accelerated vesting provisions upon retirement will need to be fully expensed by the period in which the employee becomes eligible to retire. At December 31, 2005, unrecognized compensation cost for such share-based awards held by retirement eligible employees was not material.
SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. The modified prospective method applies the recognition provisions to all awards granted or modified after the adoption date of this Statement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective. For details regarding current accounting for share-based awards, see Note 10, Executive Incentive Compensation.
The SEC issued SAB No. 107 to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. Also, the SEC issued SAB No. 107 to provide the staff's views regarding the valuation of share-based payments, including assumptions such as expected volatility and expected term. We applied the additional guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R).
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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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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 operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged in domestic and international diversified energy businesses including independent power production, electric distribution, and natural gas transmission, storage and processing. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include CMS Energy, Consumers, Enterprises, and all other entities in which we have a controlling financial interest or of which we are the primary beneficiary, in accordance with Revised FASB Interpretation No. 46. We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. We eliminate intercompany transactions and balances.
USE OF ESTIMATES: We prepare our consolidated financial statements in conformity with U.S. 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.
ACCOUNTING FOR MISO TRANSACTIONS: CMS ERM accounts for MISO transactions on a net basis for each of the generating units for which CMS ERM sells power. CMS ERM allocates other fixed costs associated with MISO settlements back to the generating units and records billing adjustments when invoices are received. Consumers accounts for MISO transactions on a net basis for all of its generating units combined. Consumers records billing adjustments when invoices are received and also records an expense accrual for future adjustments based on historical experience.
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. In December 2005, CMS ERM extinguished one of the outstanding obligations for $118 million, which included a $9 million loss on extinguishment.
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.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CASH EQUIVALENTS, RESTRICTED CASH, AND RESTRICTED SHORT-TERM INVESTMENTS: All highly liquid investments with an original maturity of three months or less are considered cash equivalents.
At December 31, 2005, our restricted cash and restricted short-term investments on hand was $198 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. Restricted short-term investments consist of $128 million of U.S. Treasury securities deposited with a trustee for the purpose of extinguishing the current portion of long-term debt -- related parties. These investments have original maturity dates of less than one year and, because of their short-term maturities, carrying amounts approximate fair value.
COLLECTIVE BARGAINING AGREEMENTS: At December 31, 2005, approximately 45 percent of Consumers' employees were represented by the Utility Workers of America Union. The Union represents Consumers' operating, maintenance, and construction employees and call center employees.
COST METHOD INVESTMENTS: Our cost method investments totaled $19 million at December 31, 2005 and $22 million at December 31, 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 the number of shares of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable. Diluted EPS excludes the impact of antidilutive securities, which are those securities resulting in an increase in EPS or a decrease in loss per share. For earnings per share computation, see Note 5, Earnings Per Share.
FINANCIAL AND DERIVATIVE 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.
We account for derivative instruments using SFAS No. 133. Derivatives are reported on the balance sheet at their fair value. Changes in fair value are recorded to accumulated other comprehensive income if the derivative qualifies for cash flow hedge accounting; otherwise, the changes are recorded to earnings.
For additional details regarding financial and derivative instruments, see Note 6, Financial and Derivative Instruments.
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, also included in this category, is stated at the lower of cost or market and valued using the last-in, first-out (LIFO) method. The amount of reserve to reduce the MCV Partnership's inventory from the first-in, first-out (FIFO) basis to the LIFO basis was $15 million at December 31, 2005 and
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$10 million at December 31, 2004. Inventory cost determined on a FIFO basis approximates current replacement cost.
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. There is no goodwill at the electric and gas utility segments.
The changes in the carrying amount of goodwill at the Enterprises segment for the years ended December 31, 2004 and 2005 are included in the following table:
- -------------------------
(a) 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.
IMPAIRMENT OF LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: We evaluate potential impairments of our long-lived assets, other than goodwill, based on various analyses, including the projection of undiscounted cash flows, whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the carrying amount of the asset exceeds its estimated undiscounted future cash flows, an impairment loss is recognized and the asset is written down to its estimated fair value.
We also assess our ability to recover the carrying amounts of our equity method investments whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. This assessment requires us to determine the fair values of our equity method investments. 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. 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.
For additional details, see Note 2, Asset Impairment Charges, Sales, and Discontinued Operations.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY: Our subsidiaries and affiliates whose functional currency is not the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect at the end of the fiscal period. We translate revenue and expense accounts of such subsidiaries and affiliates into U.S. dollars at the average exchange rates that prevailed during the period. These foreign currency translation adjustments are shown in the stockholders' equity section on our Consolidated Balance Sheets. 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.
At December 31, 2005, the Foreign Currency Translation component of stockholders' equity is $313 million, which primarily represents currency losses in Argentina and Brazil. The net foreign currency loss due to the unfavorable exchange rate of the Argentine peso using an exchange rate of 3.038 pesos per U.S. dollar was $265 million. The net foreign currency loss due to the unfavorable exchange rate of the Brazilian real using an exchange rate of 2.33 reals per U.S. dollar was $51 million.
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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. Our DOE liability is $145 million at December 31, 2005 and $141 million at December 31, 2004. This amount includes 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, along with associated cost of removal net of salvage. Cost of removal collected from our customers, but not spent, is recorded as a regulatory liability. An allowance for funds used during construction is capitalized on regulated major construction projects. With respect to the retirement or
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disposal of non-regulated assets, the resulting gains or losses are recognized in income. For additional details, see Note 8, Asset Retirement Obligations and Note 12, Property, Plant, and Equipment.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for comparative purposes. These reclassifications did not affect consolidated net income (loss) for the years presented.
RELATED-PARTY TRANSACTIONS: We received income from related parties as follows:
We recorded expense from related parties as follows:
- ------------------------- (a) We issued Trust Preferred Securities through several CMS Energy and Consumers affiliated companies. At 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.
(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, Consolidation of Variable Interest Entities.
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 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 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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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 seven years.
- ------------------------- (a) At December 31, 2005, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.781 billion of regulatory assets as non-current regulatory assets. At December 31, 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, 2005 and December 31, 2004, all of our regulatory liabilities represented non-current regulatory liabilities.
2: ASSET IMPAIRMENT CHARGES, SALES, AND DISCONTINUED OPERATIONS
ASSET IMPAIRMENT CHARGES
The following table summarizes our asset impairments:
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- ------------------------- (a) The MCV Partnership's costs of producing electricity are tied to the price of natural gas, but its revenues do not vary with changes in the price of natural gas. In 2005, NYMEX forward natural gas price forecasts for the years 2005 through 2010 increased substantially. Additionally, other independent natural gas long-term forward price forecasting organizations indicated their intention to raise their forecasts for the price of natural gas generally over the entire long-term forecast horizon beyond 2010. Our analysis and assessment of this information suggested that forward natural gas prices for the period from 2006 through 2010 could average approximately $9 per mcf. Further, this information indicated that natural gas prices could average approximately $6.50 per mcf over the long term beyond 2010. As a result, in 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and determined that an impairment analysis, considering revised forward natural gas price assumptions, was required. In its impairment analysis, the MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows at a 4.3 percent risk free interest rate. The carrying value of the MCV Partnership's fixed assets exceeded the estimated fair value, resulting in an impairment charge of $1.159 billion to recognize the reduction in fair value of the MCV Facility's fixed assets. As a result, our 2005 net income was reduced by $369 million after accounting for minority interest and tax effects. After reflecting the impairment charge, the MCV Partnership's fixed assets, which are included on our Consolidated Balance Sheets and reported under the Enterprises business segment, are valued at $224 million at December 31, 2005.
If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected, which could result in the MCV Partnership failing to meet its obligations under the sale and leaseback transactions and other contracts, and could result in an impairment of the FMLP. At December 31, 2005, Consumers' investment in the FMLP was $235 million.
Our 49 percent interest in the MCV Partnership is held through Consumers' wholly-owned subsidiary, CMS Midland. The severe adverse change in the anticipated economics of the MCV Partnership operations discussed within this Note also led to our decision to impair certain assets carried on the balance sheet of CMS Midland. These assets represented interest capitalized during the construction of the MCV Facility, which were being amortized over the life of the MCV Facility. In the third quarter of 2005, we recorded an impairment charge of $25 million ($16 million, net of tax) to reduce the carrying amount of these assets to zero.
The total of the CMS Midland impairment and the MCV Partnership impairment previously discussed is $1.184 billion, before tax, and $385 million net of taxes and minority interest.
(b) In the first quarter of 2004, an impairment charge was recorded to recognize the reduction in fair value as a result of the sale of Loy Yang, completed in April 2004, which included a cumulative net foreign currency translation loss of approximately $110 million.
(c) 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.
(d) In December 2004, we recorded impairment charges to adjust our carrying value to fair market value as a result of the planned sale of our investment in GVK. We closed on the sale of GVK in February 2005.
ASSET SALES
Gross cash proceeds received from the sale of assets, including discontinued operations, totaled $61 million in 2005, $219 million in 2004, and $939 million in 2003.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For the year ended December 31, 2005, we sold the following assets:
- ------------------------- (a) In February 2005, we sold our interest in GVK, a 250 MW gas-fired power plant located in South Central India, for $21 million.
(b) In April 2005, we sold our investment in the Scudder Latin American Power Fund and received gross cash proceeds of $23 million.
(c) In April 2005, we received gross cash proceeds of $15 million for the sale of a gas turbine and auxiliary equipment. There was no gain or loss on the sale.
For the year ended December 31, 2004, we sold the following assets:
For the year ended December 31, 2003, we sold the following assets:
The impacts of these sales are included in Gain (loss) on assets sales, net on our Consolidated Statements of Income (Loss). Although most of our asset sales program is complete, we still may sell certain remaining businesses or assets as opportunities arise.
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DISCONTINUED OPERATIONS
We have discontinued the following operations:
The following amounts are reflected in the Consolidated Statements of Income (Loss), in the Gain (Loss) From Discontinued Operations line:
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(a) In December 2005, we received an arbitration award related to a discontinued operation. This award resulted in proceeds of $13 million ($9 million after-tax). Additional adjustments include a reduction of a contingent liability and a settlement of a tax contingency.
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 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. There was no interest expense allocated to discontinued operations in 2005, less than $1 million for 2004, and $22 million for 2003.
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.
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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 nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading by CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals, in accordance with existing indemnification policies.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates, including but not limited to Consumers which, while established, operated and regulated as a separate legal entity and publicly traded company, shares a parallel Board of Directors with CMS Energy. 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 running from May 2000 through March 2003. The cases were consolidated into a single lawsuit. The consolidated lawsuit generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, a motion was granted, dismissing Consumers and three of the individual defendants, but the court denied the motions to dismiss for CMS Energy and the 13 remaining individual defendants. Plaintiffs filed a motion for class certification on April 15, 2005 and an amended motion for class certification on June 20, 2005. The hearing on this motion is scheduled for February 28, 2006. On September 20, 2005, CMS Energy filed a motion for judgment on the pleadings, based on the Dura Pharmaceuticals decision issued by the United States Supreme Court. Plaintiffs filed their response on October 25, 2005, along with a so-called "cross-motion for partial summary judgment" seeking a determination that CMS Energy is liable for all damages proximately caused by its "culpable conduct." On November 29, 2005, the judge issued a decision denying both CMS Energy's motion for judgment on the pleadings and plaintiffs' cross-motion for partial summary judgment. CMS Energy and the individual defendants will defend themselves vigorously in this litigation but cannot predict its outcome.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST, and certain named and unnamed officers and directors, in two lawsuits brought as purported class actions on behalf of participants and beneficiaries of the CMS Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July 2002 in United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended consolidated complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge has conditionally granted plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than mid-2006 in the absence of an intervening settlement of the lawsuits. Settlement negotiations among counsel for the parties and CMS Energy's fiduciary insurance carrier are ongoing. In the absence of such a settlement, CMS Energy and Consumers will defend themselves vigorously in this litigation but cannot predict its outcome.
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
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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. CMS Energy is currently advancing legal defense costs to the two individuals in accordance with existing indemnification policies.
BAY HARBOR: As part of the development of Bay Harbor by certain subsidiaries of CMS Energy, which went forward under an agreement with the MDEQ, a third party constructed a golf course over several abandoned cement kiln dust (CKD) piles left over from the former cement plant operation on the Bay Harbor site. Pursuant to the agreement with the MDEQ, CMS Energy constructed a water collection system to recover seep water from one of the CKD piles. In 2002, CMS Energy sold its interest in Bay Harbor, but retained its obligations under previous environmental indemnifications entered into at the inception of the project.
In September 2004, the MDEQ issued a notice of noncompliance (NON), after finding high-pH seep water in Lake Michigan adjacent to the property. The MDEQ also found higher than acceptable levels of heavy metals, including mercury, in the seep water.
In February 2005, the EPA executed an Administrative Order on Consent (AOC) to address problems at Bay Harbor, upon the consent of CMS Land Company, a subsidiary of Enterprises and CMS Capital, LLC, a subsidiary of CMS Energy. Under the AOC, CMS Land Company and CMS Capital, LLC are 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 "removal action work 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. The EPA approved a final removal action work plan in September 2005.
The EPA-approved removal action work plan provides for fencing of affected beachfront areas and installing an underground leachate collection system, among other elements. Shoreline areas, where the leachate collection system is installed, are routinely monitored for effectiveness. To date, the collection system has proven to be effective. The EPA's approvals also specify that a backup "containment and isolation system," involving dams or barriers in the lake, could be required in certain areas, if the collection system is ineffective. In addition, there are indications that CKD may be located on the beach at the west end of the collection system installation. As a result, construction in the affected area has been halted pending further investigation. CMS Energy has worked out a schedule with the EPA to perform further investigation of these conditions and will deliver a conceptual design to the EPA for a remediation system. CMS Energy is presently engaged in negotiations with the EPA and the MDEQ concerning potential interim remediation activities for the Eastern CKD pile, which may include a carbon dioxide injection system to neutralize high-pH materials and/or a collection system or systems.
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. Several landowners have threatened litigation in the event their demands are not met and owners of one parcel have filed a lawsuit in Emmet County Circuit Court against CMS Energy and several of its subsidiaries, as well as Bay Harbor Company LLC and David Johnson, one of the developers at Bay Harbor. 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 has entered into various access, purchase and settlement agreements with several of the affected landowners at Bay Harbor and continues negotiations with other landowners for access as necessary to implement remediation measures. CMS Energy will defend vigorously any property damage and personal injury claims or lawsuits.
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CMS Energy originally recorded a liability for its obligations associated with this matter in the amount of $45 million in the fourth quarter of 2004. Under the AOC, CMS Land Company is presently conducting a remedial investigation of the site, which includes the gathering and analysis of data to be utilized in arriving at a permanent fix. Based on the evaluation of recent construction events and site-related data, CMS Energy has increased its liability for its obligations to $85 million and accordingly, increased the reserve by $40 million. An adverse outcome of this matter, depending on the size of any indemnification obligation or liability under environmental laws, could 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: Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $815 million. The key assumptions in the capital expenditure estimate include:
- construction commodity prices, especially construction material and labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- 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 8.3 percent. As of December 2005, we had incurred $605 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $210 million of capital expenditures will be made in 2006 through 2011. These expenditures include installing selective catalytic control reduction technology at four of our coal-fired electric plants. In addition to modifying coal-fired electric plants, our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $10 million per year, which we expect to recover from our customers. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the coal-fired electric generating units emit nitrogen oxide. The expense is recovered from our customers through the PSCR process.
The EPA recently adopted a Clean Air Interstate Rule that requires additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. The rule involves a two-phase program to reduce emissions of sulfur dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule will require that we run our selective catalytic control technology units year round beginning in 2009 and may require that we purchase additional nitrogen oxide allowances beginning in 2009.
In addition to the selective catalytic control technology installed to meet the nitrogen oxide standards, our current plan includes installation of flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to meet the Phase I reduction requirements of the Clean Air Interstate Rule, at costs similar to those to comply with the nitrogen oxide standards. We currently have a surplus of sulfur dioxide allowances, which were granted by the EPA and are accounted for as inventory. In January 2006, we sold some of our excess sulfur dioxide allowances for $61 million and recognized the proceeds as a regulatory liability.
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In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric power plants by 2010 and further reductions by 2018. While the industry has not reached a consensus on the technical methods for curtailing mercury emissions, our capital and operating costs for mercury emissions reductions are expected to be significantly less than what was required for selective catalytic reduction technology used for nitrogen oxide compliance.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to certain aspects of EPA's Clean Air Mercury Rule, asserting that the rule is inadequate. The MDEQ has not indicated the direction that it will pursue to meet or exceed the EPA requirements through state rulemaking. We are actively participating in dialog with the MDEQ regarding potential paths for controlling mercury emissions and meeting the EPA requirements. In October 2005, the EPA announced it would reconsider certain aspects of the Clean Air Mercury Rule. We cannot predict the outcome of this proceeding.
The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seeking 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.
Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental Protection Act, we expect that we will ultimately incur investigation and remedial action costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies.
We are a potentially responsible party at several contaminated sites administered under Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties with substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for the known Superfund sites will be between $2 million and $10 million. At December 31, 2005, 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 Ludington. 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.
MCV Environmental Issue: On July 12, 2004, the MDEQ, Air Control Division, issued the MCV Partnership a Letter of Violation asserting that the MCV Facility violated its Air Use Permit to Install (PTI) by exceeding the carbon monoxide emission limit on the Unit 14 duct burner and failing to maintain certain records in the required format. The MCV Partnership has declared five of the six duct burners in the MCV Facility as unavailable for operational use (which reduces the generation capability of the MCV Facility by approximately 100 MW) and took other corrective action to address the MDEQ's assertions. The one available duct burner was tested in April 2005 and its emissions met permitted levels due to the configuration of that particular unit. The MCV Partnership disagrees with certain of the MDEQ's assertions. The MCV Partnership filed a response in July 2004 to address the Letter of Violation. On December 13, 2004, the MDEQ informed the MCV Partnership that it was pursuing an escalated enforcement action against the MCV Partnership regarding the alleged violations of the MCV Facility's PTI. The MDEQ also stated that the alleged violations are deemed federally significant and, as such, placed the MCV Partnership on the EPA's High Priority Violators List (HPVL). The MDEQ and the MCV Partnership are pursuing voluntary settlement of this matter, which will satisfy state and federal requirements and remove the MCV Partnership from the HPVL. Any such settlement may involve a fine, but at this time, the MDEQ has not stated what, if any, fine they will seek to impose. At this time, the MCV Partnership management cannot predict the financial impact or outcome of this issue.
On July 13, 2004, the MDEQ, Water Division, issued the MCV Facility a Notice Letter asserting the MCV Facility violated its National Pollutant Discharge Elimination System (NPDES) Permit by discharging heated
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process wastewater into the storm water system, failing to document inspections, and other minor infractions (alleged NPDES violations). In August 2004, the MCV Partnership filed a response to the MDEQ letter covering the remediation for each of the MDEQ's alleged violations. On October 17, 2005, the MDEQ, Water Bureau, issued the MCV Partnership a Compliance Inspection report, which listed several minor violations and concerns that needed to be addressed by the MCV Facility. This report was issued in connection with an inspection of the MCV Facility in September 2005, which was conducted for compliance and review of the Storm Water Pollution Prevention Plans (SWPPP). The MCV Partnership submitted its updated SWPPP on December 1, 2005. The MCV Partnership management believes it has resolved all issues associated with the Notice Letter and Compliance Inspection and does not expect any further MDEQ actions on these matters.
ALLOCATION OF BILLING COSTS: In February 2006, the MPSC issued an order which determined that Consumers violated the MPSC code of conduct by including a bill insert advertising an unregulated service. The MPSC issued a penalty of $45,000 and stated that any subsidy for the use of Consumers' billing system arising from past code of conduct violations will be accounted for in our next electric rate case. We cannot predict the outcome or the impact on any future electric rate case.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. 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 plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The plaintiffs also filed suit in the United States Court for the Western District of Michigan, which the judge subsequently dismissed. The plaintiffs have appealed the dismissal to the United States Court of Appeals. We cannot predict the outcome of these appeals.
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC ROA: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of our total distribution load. It is difficult to predict future ROA customer trends.
STRANDED COSTS: Prior MPSC orders adopted a mechanism pursuant to the Customer Choice Act to provide recovery of Stranded Costs that occur when customers leave our system to purchase electricity from alternative suppliers. In November 2005, we filed an application with the MPSC related to the determination of 2004 Stranded Costs. Applying the Stranded Cost methodology used in prior MPSC orders, we concluded that we experienced zero Stranded Costs in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
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 covering partially the estimated reserve margin requirements for 2006 through 2010. As a result, we have recognized an asset of $6 million for unexpired capacity and energy contracts at December 31, 2005. The total premium costs of electric capacity and energy contracts for 2005 were approximately $8 million.
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PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. Revenues from the PSCR charges are subject to reconciliation after actual costs are reviewed for reasonableness and prudence. In March 2005, we submitted our 2004 PSCR reconciliation filing to the MPSC.
In September 2005, we submitted our 2006 PSCR plan filing to the MPSC. In November 2005, we submitted an amended 2006 PSCR plan to the MPSC to include higher estimates for certain transmission and coal supply costs. In December 2005, the MPSC issued an order that temporarily excludes a portion of the increased costs from our PSCR charge. The order also includes a one mill per kWh reduction in the PSCR charge. We implemented this PSCR charge in January 2006. If the temporary order remains in effect for the remainder of 2006, it would result in a delay in the recovery of $87 million related to these excluded power supply costs. We expect to recover fully these costs through the PSCR process. To the extent that we incur and are unable to collect these costs in a timely manner, our cash flows from electric utility operations will be affected negatively. We are seeking full recovery of filed 2006 costs in 2006 as part of this proceeding. 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. 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, Consolidation of Variable Interest Entities.
Under the MCV 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. Natural gas prices have increased substantially in recent years and throughout 2005. In 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and recorded an impairment charge. If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected and could result in the MCV Partnership failing to meet its obligations under the sale and leaseback transactions and other contracts. For additional details on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges, Sales, and Discontinued Operations. We are evaluating various alternatives in order to develop a new long-term strategy with respect to the MCV Facility.
Further, the cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. Underrecoveries of capacity and fixed energy payments totaled $59 million in 2005, and were expensed directly to income. We estimate underrecoveries of $55 million in 2006 and $39 million in 2007. However, Consumers' direct savings from the RCP, after allocating a portion to customers, are used to offset our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 15, 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out clause, the MCV Partnership may have the right to terminate the MCV PPA. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 15, 2007 may affect negatively the financial performance of the MCV Partnership.
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 reduces the MCV Facility's annual production of electricity and, as a result, reduces the MCV Facility's consumption of
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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 MCV Facility fuel cost savings are first used to offset fully the cost of replacement power. Second, $5 million annually, funded jointly by Consumers and the MCV Partnership, is contributed to our RRP. Remaining savings are split between the MCV Partnership and Consumers. Consumers shared 50 percent of its direct savings in 2005, and will share 70 percent of its direct savings in 2006 and beyond. 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, we implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed for rehearing of the MPSC order approving the RCP. The Attorney General also filed an appeal with the Michigan Court of Appeals. We cannot predict the outcome of these matters.
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 City of Midland appealed the decision to the Michigan Court of Appeals, and the MCV Partnership 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 2005. The MCV Partnership estimates that the 1997 through 2005 tax year cases will result in a refund to the MCV Partnership of approximately $83 million, inclusive of interest, if the decision of the Michigan Tax Tribunal is upheld. In February 2006, the Michigan Court of Appeals primarily affirmed the Michigan Tax Tribunal decision, but remanded the case back to the Michigan Tax Tribunal to clarify certain aspects of the Tax Tribunal decision. The remanded proceedings may result in the determination of a greater refund to the MCV Partnership. The MCV Partnership cannot predict the outcome of these proceedings; therefore, this anticipated refund has not been recognized in 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 decommissioning, this estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. Recently updated cost projections for Big Rock indicate an anticipated decommissioning cost of $395 million as of the end of 2005.
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BIG ROCK: In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. Excluding the additional nuclear fuel storage costs due to the DOE's failure to accept 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 $57 million. At this time, we plan to provide the additional amounts needed from our corporate funds and, subsequent to the completion in 2007 of radiological decommissioning work, seek recovery of such expenditures from some alternative source. We cannot assume that such efforts will be successful. 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, 2005, we have an investment in nuclear decommissioning trust funds of $10 million for Big Rock. In addition, at December 31, 2005, we have charged $9 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.
PALISADES: Excluding additional nuclear fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we concluded, based on the costs estimates filed in March 2004, that the existing surcharge for Palisades needed to be increased to $25 million annually, beginning January 1, 2006, and continuing 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 January 2005, we filed a settlement agreement with the MPSC that was agreed to by four of the six parties involved in the proceeding. 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. In September 2005, the MPSC approved the contested settlement. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability.
At December 31, 2005, we have an investment in the MPSC nuclear decommissioning trust funds of $534 million for Palisades. In addition, at December 31, 2005, we have a FERC decommissioning trust fund with a balance of $11 million. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 8, Asset Retirement Obligations.
In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. Certain parties are seeking to intervene and have requested a hearing on the application. The NRC has stated that it expects to take 22-30 months to review a license renewal application. We expect a decision from the NRC in 2007. At this time, we cannot determine what impact this will have on decommissioning costs or the adequacy of funding.
In December 2005, we announced plans to sell Palisades and have begun pursuing this asset divestiture. As a sale is not probable to occur until a firm purchase commitment is entered into with a potential buyer, we have not classified the Palisades assets as held for sale on our Consolidated Balance Sheets.
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.
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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. On April 29, 2005, the court ruled on various motions for summary judgment filed by the DOE and us. The court denied the DOE's motions to dismiss portions of the complaint including its motion seeking recovery of a one-time fee payable by us prior to delivery of the spent nuclear fuel. The court granted the DOE's motion to recoup this fee against any damages awarded to us. The court granted our motion for summary judgment on liability. If our litigation against the DOE is successful, we plan to use any 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, in due course, will submit a final license application to the NRC for the repository. The application and review process is estimated to take several years.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $28 million in any policy year if insured losses in excess of NEIL's maximum policyholders surplus occur at our, or any other member's, nuclear facility. NEIL's policies include coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear energy hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. 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 $15 million.
We also maintain insurance under a program that covers tort claims for bodily injury to nuclear workers caused by nuclear hazards. The policy contains a $300 million nuclear industry aggregate limit. Under a previous insurance program providing coverage for claims brought by nuclear workers, we remain responsible for a maximum assessment of up to $6 million. This requirement will end December 31, 2007.
Big Rock remains insured for nuclear liability 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 remediation costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through insurance proceeds and MPSC-approved rates. At December 31, 2005, we have a liability of $29 million, net of $53 million of expenditures incurred to date, and a
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regulatory asset of $62 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.
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 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.
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.
We have one GCR reconciliation filing pending with the MPSC for the 2004-2005 GCR year. It was filed in June 2005. We have calculated a $2 million net overrecovery for the GCR year, including interest through March 2005 and refunds that we received from our suppliers, that are required to be refunded to our customers. The case schedule has been suspended to allow for settlement discussions.
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 proposed 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 purchased natural gas 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.
In June 2005, four of the five parties filed a settlement agreement. The fifth party filed a statement of non-objection. The settlement agreement includes a GCR ceiling price adjustment contingent upon future events.
In September 2005, we filed a motion with the MPSC seeking to reopen our GCR plan for year 2005-2006. Since the settlement agreement entered into in June 2005, there have been unanticipated increases in the market price for natural gas.
In November 2005, the MPSC issued an Order related to our reopened GCR plan for year 2005-2006. The order approved the June 2005 settlement agreement along with a new GCR factor consisting of a fixed cap of $10.10 per mcf for the December 2005 through March 2006 billing period. Our GCR factor for the billing month of February 2006 is $8.20 per mcf. One of the intervenors in this case has appealed the MPSC Order to the Michigan Court of Appeals. We are unable to predict the outcome of this appeal.
GCR plan for year 2006-2007: In December 2005, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2006 through March 2007. Our request proposed using a GCR factor consisting of:
- a base GCR factor of $11.10 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future events.
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2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously ordered $34 million reduction in our depreciation expense,
- required us to undertake a study to determine why our plant removal costs are in excess of other regulated Michigan natural gas utilities, and
- required us to file a study report with the MPSC Staff on or before December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.
We are also required to file our next gas depreciation case within 90 days after the MPSC issuance of a final order in the pending case related to ARO accounting. We expect an MPSC order in the first quarter of 2006.
If the depreciation case order is issued after the gas general rate case order, we proposed to incorporate its results into the gas general rates using a surcharge mechanism.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking a 12 percent authorized return on equity along with a $132 million annual increase in our gas delivery and transportation rates. The primary reasons for the request are recovery of new investments, carrying costs on natural gas inventory related to higher gas prices, system maintenance, employee benefits, and low-income assistance. If approved, the request would add approximately 5 percent to the typical residential customer's average monthly bill. The increase would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million. The MPSC Staff and intervenors filed interim rate relief testimony on October 31, 2005. In its testimony, the MPSC Staff recommended granting interim rate relief of $38 million. As of February 2006, the MPSC has not acted on our interim rate relief request.
On February 13, 2006, the MPSC Staff recommended granting final rate relief of $62 million. The MPSC Staff proposed that $17 million of this amount be contributed to a low income energy efficiency fund. The MPSC Staff also recommended reducing our return on common equity to 11.15 percent, from our current 11.4 percent.
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, Tennessee and Kansas. CMS Energy and the other CMS Energy 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, filed an arbitration claim against DFD asserting in excess of an additional
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$75 million in claims against DFD. The judge in the Michigan state court case entered an order staying DFD's prosecution of its claims in the court case and permitting the arbitration to proceed. The arbitration hearing began October 10, 2005 and is scheduled to continue through mid-2006. DIG will continue to defend itself vigorously and pursue its claims. CMS Energy cannot predict the outcome of this matter.
FORMER CMS OIL AND GAS OPERATIONS: A Michigan trial judge granted Star Energy, Inc. and White Pine Enterprises, LLC a declaratory judgment in an action filed in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas subsidiary, violated an oil and gas lease and other arrangements by failing to drill wells it had committed to drill. A jury then awarded the plaintiffs a $7.6 million award. Terra appealed this matter to the Michigan Court of Appeals. The Michigan Court of Appeals reversed the trial court judgment with respect to the appropriate measure of damages and remanded the case for a new trial on damages. The trial judge reinstated the judgment against Terra and awarded Terra title to the minerals. Terra appealed this judgment. The court of appeals heard arguments on May 19, 2005 and issued an opinion on May 26, 2005 remanding the case to the trial court for a new trial on damages. The plaintiffs filed an application for leave to appeal with the Michigan Supreme Court, which was denied. Enterprises has an indemnity obligation with regard to losses to Terra that might result from this litigation.
CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase agreement, CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery in La Plata, Argentina. As a result of the so-called "Emergency Laws," payments by YPF Repsol under the power purchase agreement have been converted to pesos at the exchange rate of one U.S. dollar to one Argentine peso. Such payments are currently insufficient to cover CMS Ensenada's operating costs, including quarterly debt service payments to the Overseas Private Investment Corporation (OPIC). Enterprises is party to a Sponsor Support Agreement pursuant to which Enterprises has guaranteed CMS Ensenada's debt service payments to OPIC up to an amount which is in dispute, but which Enterprises estimates 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 arbitration on the matter, to be administered by the International Chamber of Commerce. The arbitration hearing was held in July 2005 and a decision from the arbitration panel is expected in the first quarter of 2006.
ARGENTINA: As part of its energy privatization incentives, Argentina directed CMS Gas Transmission to calculate tariffs in U.S. dollars, then convert them to pesos at the prevailing exchange rate, and to adjust tariffs every six months to reflect changes in inflation. Starting in early 2000, Argentina suspended the inflation adjustments.
In January 2002, the Republic of Argentina enacted the Public Emergency and Foreign Exchange System Reform Act. This law repealed the fixed exchange rate of one U.S. dollar to one Argentine peso, converted all dollar-denominated utility tariffs and energy contract obligations into pesos at the same one-to-one exchange rate, and directed the Government of Argentina to renegotiate such tariffs.
CMS Gas Transmission began arbitration proceedings against the Republic of Argentina (Argentina) under the auspices of the International Centre for the Settlement of Investment Disputes (ICSID) in mid-2001, citing breaches by Argentina of the Argentine-U.S. Bilateral Investment Treaty (BIT). In May 2005, an ICSID tribunal concluded, among other things, that Argentina's economic emergency did not excuse Argentina from liability for violations of the BIT. The ICSID tribunal found in favor of CMS Gas Transmission, and awarded damages of U.S. $133 million, plus interest.
The ICSID Convention provides that either party may seek annulment of the award based upon five possible grounds specified in the Convention. Argentina's Application for Annulment was formally registered by ICSID on September 27, 2005 and will be considered by a newly constituted panel.
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On December 28, 2005, certain insurance underwriters paid the sum of $75 million to CMS Gas Transmission in respect of their insurance obligations resulting from non-payment of the ICSID award. The payment, plus interest, is subject to repayment by CMS Gas Transmission in the event that the ICSID award is annulled. Pending the outcome of the annulment proceedings, CMS Energy recorded the $75 million payment as deferred revenue at December 31, 2005.
IRS RULING: In August 2005, the IRS issued Revenue Ruling 2005-53 and regulations to provide guidance with respect to the use of the "simplified service cost" method of tax accounting. We use this tax accounting method, generally allowed by the IRS under section 263A of the Internal Revenue Code, with respect to the allocation of certain corporate overheads to the tax basis of self-constructed utility assets. Under the IRS guidance, significant issues with respect to the application of this method remain unresolved and subject to dispute. However, the effect of the IRS's position may be to require CMS Energy either (1) to repay a portion of previously received tax benefits, or (2) to add back to taxable income, half in each of 2005 and 2006, a significant portion of previously deducted overheads. The impact of this matter on future earnings, cash flows, or our present NOL carryforwards remains uncertain, but could be material. We have recorded a reduction in our NOL carryforwards of $359 million in 2005, and a corresponding reduction in deferred taxes related to property, to reflect the estimated 2005 effect of the new regulation. For additional information, see Note 9, Income Taxes. CMS Energy cannot predict the outcome of this matter.
OTHER: In addition to the matters disclosed within this Note, Consumers and certain other subsidiaries of CMS Energy are parties to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or future results of operations.
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: The Interpretation requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee. The initial recognition and measurement provision of this Interpretation does not apply to some guarantee contracts, such as product warranties, derivatives, or guarantees between corporations under common control, although disclosure of these guarantees is required.
The following table describes our guarantees at December 31, 2005:
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(a) The majority of this amount arises from routine provisions in stock and asset sales agreements under which we indemnify the purchaser for losses resulting from events such as claims resulting from tax disputes and the failure of title to the assets or stock sold by us to the purchaser. We believe the likelihood of a loss for any remaining indemnifications to be remote.
(b) In connection with our environmental remediation efforts at Bay Harbor, we have provided certain property owners with put options, which require us to purchase their properties under certain conditions. Some options may not be exercised for at least three years from the effective date of the option agreements unless certain events, such as bankruptcy or death of a spouse occur. If we were required to perform under these agreements, the maximum amount of our obligation would be equal to an amount representing the fair market value of the properties at that time, excluding any effects on the fair market value resulting from CKD-related environmental conditions. Expiration dates for these agreements vary from July 2013 to November 2017. At December 31, 2005, we recognized a liability of $1 million related to the options.
The following table provides additional information regarding our guarantees:
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At December 31, 2005, none of our guarantees contained provisions allowing us to recover, from third parties, any amount paid under the guarantees. In the ordinary course of business, we enter into agreements containing tax and other indemnification provisions in connection with a variety of transactions, including the sale of subsidiaries and assets, equipment leasing, service agreements, employment agreements, and financing agreements. While we cannot estimate our maximum exposure under these indemnities, we consider the probability of liability remote.
Project Financing: We enter into various project-financing security arrangements such as equity pledge agreements and share mortgage agreements to provide financial or performance assurance to third parties on behalf of certain unconsolidated affiliates. Expiration dates for these agreements vary from March 2015 to June 2020 or terminate upon payment or cancellation of the obligation. Non-payment or other act of default by an unconsolidated affiliate would trigger enforcement of the security. If we were required to perform under these agreements, the maximum amount of our obligation under these agreements would be equal to the value of the shares relinquished to the guaranteed party at the time of default.
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4: FINANCINGS AND CAPITALIZATION
Long-term debt at December 31 follows:
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(a) Contingently convertible notes. See "Contingently Convertible Securities" section within this Note for further discussion of the conversion features.
(b) Represents the weighted average interest rate of $220 million of general term notes at December 31, 2004.
(c) Represents the weighted average interest rate at December 31, 2005 (5.188 percent at December 31, 2004).
(d) Maturity date uncertain.
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FINANCINGS: The following is a summary of significant long-term debt issuances and retirements during 2005:
- -------------------------
(a) The CMS Generation bank loan is a $150 million term loan in two tranches. Tranche A outstanding is $102 million and bears interest at six month LIBOR plus 250 basis points (7.17 percent at December 31, 2005.) Tranche B outstanding is 40 million Euros (US dollar equivalent of $47 million at December 31, 2005) and bears interest at six month EURIBOR plus 250 basis points (5.12 percent at December 31, 2005). The term loan matures in December 2008.
Costs associated with CMS Energy's 2005 senior notes issuances totaled $5 million and are being amortized over the lives of the related debt. Costs associated with Consumers' 2005 debt issuances totaled $13 million and are also being amortized over the lives of the related debt. Call premiums associated with CMS Energy's debt retirements totaled $10 million and were charged to other expense. Call premiums associated with Consumers' debt retirements totaled $10 million and are being amortized over the lives of the newly issued debt.
FIRST MORTGAGE BONDS: Consumers secures its FMB 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
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indenture, its articles of incorporation, and the need for regulatory approvals under federal law. See "FMB Indenture Limitations" section within this Note.
SECURITIZATION BONDS: Certain regulatory assets collateralize Securitization bonds. Consumers is not the owner of these 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 collected are remitted to a trustee for the Securitization bonds and are not available to creditors of Consumers or its affiliates. Securitization surcharges totaled $50 million annually in 2005 and in 2004.
FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB Interpretation No. 46. At December 31, long-term debt of the FMLP consists of:
The FMLP debt is 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 themselves. The sole assets of the trusts consist of the debentures described in the following table. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trusts issued. We determined that we do not hold the controlling financial interest in our trust preferred security structures. Accordingly, those entities are reflected in Long-term debt -- related parties.
The following is a summary of Long-term debt -- related parties at December 31:
- -------------------------
(a) Extinguished in February 2006.
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.
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CMS Energy and Consumers, as applicable, have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debentures, related indenture and trust documents, provide full and unconditional guarantees for the trusts' obligations under the preferred securities.
DEBT MATURITIES: At December 31, 2005, the aggregate annual maturities for long-term debt and long-term debt -- related parties for the next five years are:
- -------------------------
(a) Includes $150 million of CMS Energy's contingently convertible senior notes and $129 million of long-term debt -- related parties. See "Contingently Convertible Securities" section within this Note.
REGULATORY AUTHORIZATION FOR FINANCINGS: In April 2005, the FERC issued an authorization to permit Consumers to issue up to an additional $1.0 billion ($2.0 billion in total) of long-term securities for refinancing or refunding purposes, and up to an additional $1.0 billion ($2.5 billion in total) of long-term securities for general corporate purposes during the period ending June 30, 2006.
Combined with remaining availability from previously issued FERC authorizations, Consumers can now issue up to:
- $876 million of long-term securities for refinancing or refunding purposes,
- $1.159 billion of long-term securities for general corporate purposes, and
- $1.935 billion of long-term FMB to be issued solely as collateral for other long-term securities.
FMB INDENTURE LIMITATIONS: Irrespective of Consumers' existing FERC authorization, its ability to issue FMB as primary obligations or as collateral for financing is governed by certain provisions of their indenture dated September 1, 1945 and its subsequent supplements. Due to the adverse impact of the MCV Partnership asset impairment charge recorded in September 2005 on the net earnings coverage test in one of the governing bond-issuance provisions of the indenture, Consumers expects its ability to issue additional FMB will be limited to $298 million through September 30, 2006. After September 30, 2006, Consumers' ability to issue FMB in excess of $298 million will be based on achieving a two-times FMB interest coverage ratio.
REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities with banks are available at December 31, 2005:
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 $150 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility.
Under the provisions of its articles of incorporation, at December 31, 2005, Consumers had $179 million of unrestricted retained earnings available to pay common stock dividends. Covenants in Consumers' debt facilities
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cap common stock dividend payments at $300 million in a calendar year. During 2005, we received $277 million of common stock dividends from Consumers.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, Consumers currently sells certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. The special purpose entity sold $325 million of receivables at December 31, 2005 and $304 million of receivables at December 31, 2004. Consumers continues to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against Consumers' other assets for failure of a debtor to pay when due and no right to any receivables not sold. Consumers has neither recorded a gain or loss on the receivables sold nor retained interest in the receivables sold.
Certain cash flows under Consumers' accounts receivable sales program are shown in the following table:
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 April 2005, we issued 23 million shares of our common stock at a price of $12.25 per share. We realized net proceeds of $272 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.
PREFERRED STOCK OF SUBSIDIARY: Consumers' Preferred Stock outstanding follows:
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CONTINGENTLY CONVERTIBLE SECURITIES: At December 31, 2005, the significant terms of our contingently convertible securities were as follows:
The note holders have the right to require us to purchase the 3.375 percent convertible senior notes at par on July 15, 2008, 2013, and 2018. The note holders have the right to require us to purchase the 2.875 percent convertible senior notes at par on December 1, 2011, 2014, and 2019. On or after December 5, 2008, we may cause the 4.50 percent convertible preferred stock to convert if the closing price of our common stock remains at or above $12.86 for 20 of any 30 consecutive trading days. The $12.86 price may be adjusted if there is a payment or distribution to our common stockholders.
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. All of our contingently convertible securities require us, if converted, to pay cash up to the principal (or par) amount of the securities and any conversion value in excess of that amount in shares of our common stock. In December 2005, the trigger price contingency was met for our 4.50 percent convertible preferred stock and our 3.375 percent convertible senior notes. As a result, these securities are convertible at the option of the security holders during the three months ended March 31, 2006. As of February 2006, none of the security holders have notified us of their intention to convert these securities.
Once the 3.375 percent contingently convertible senior notes became convertible in June 2005, they held the characteristics of a current liability. Therefore, in June 2005, we reclassified the 3.375 percent contingently convertible senior notes from Long-term debt to Current portion of long-term debt. We will classify the 3.375 percent senior notes as Current portion of long-term debt during the periods that they are outstanding and convertible.
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5: EARNINGS PER SHARE
The following table presents the basic and diluted earnings per share computations:
Contingently Convertible Securities: Due to antidilution, there was no impact to diluted EPS from our contingently convertible securities for the years ended 2005 and 2003. Assuming positive income from continuing operations, our contingently convertible securities dilute EPS to the extent that the conversion value, which is based on the average market price of our common stock, exceeds the principal or par value. Had there been positive income from continuing operations for the year ended 2005, our contingently convertible securities would have contributed an additional 10.9 million shares to the calculation of diluted EPS. For additional details on our contingently convertible securities, see Note 4, Financings and Capitalization.
Stock Options and Warrants: Due to antidilution, for the year ended 2005, there was no impact to diluted EPS from options and warrants to purchase 3.5 million shares of common stock and from 1.7 million shares of unvested restricted stock. For the year ended 2004, since the exercise price was greater than the average market price of the common stock, there was no impact to diluted EPS from options and warrants to purchase 4.5 million shares of common stock. Due to antidilution, for the year ended 2003, there was no impact to diluted EPS from options and warrants to purchase 6.0 million shares of common stock.
Convertible Debentures: Due to antidilution, for the years ended 2005, 2004, and 2003, there was no impact to diluted EPS from our 7.75 percent convertible subordinated debentures. Using the if-converted method, the debentures would have:
- decreased the numerator of diluted EPS by $8.7 million from an assumed reduction of interest expense, net of tax, and
- increased the denominator of diluted EPS by 4.2 million shares.
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We can revoke the conversion rights if certain conditions are met.
In April 2005, we issued 23 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 $289 million at December 31, 2005 and $267 million at December 31, 2004. Settlement of long-term debt is generally not expected until maturity.
(b) Includes current maturities of $129 million at December 31, 2005 and $180 million at December 31, 2004.
(c) Nuclear decommissioning investments include cash and cash equivalents and accrued income totaling $12 million at December 31, 2005 and $11 million at December 31, 2004. 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 at December 31, 2005 is as follows:
Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $91 million at December 31, 2005 and $139 million at 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-term maturities, carrying amounts approximate fair value.
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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 may use various contracts to manage these risks, including swaps, options, futures, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of both:
- an executive oversight committee consisting of senior management representatives, and
- a risk committee consisting of business unit managers.
Our intention is that any increases or decreases in the value of these contracts will be offset by an opposite change in the value of the item at risk. We classify these contracts as either non-trading or trading.
The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative, it is recorded on the balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. If a derivative qualifies for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported in accumulated other comprehensive income; otherwise, the changes are reported in earnings.
For a derivative instrument to qualify for hedge accounting:
- the relationship between the derivative instrument and the item being hedged must be formally documented at inception,
- the derivative instrument must be highly effective in offsetting the hedged item's cash flows or changes in fair value, and
- if hedging a forecasted transaction, the forecasted transaction must be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or losses are recorded in accumulated other comprehensive income, those gains or losses will be reclassified into earnings in the same period or periods the hedged forecasted transaction affects earnings. If a cash flow hedge is terminated early because it is determined that the forecasted transaction will not occur, any gain or loss recorded in accumulated other comprehensive income at that date is recognized immediately in earnings. If a cash flow hedge is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and then reclassified to earnings when the forecasted transaction affects earnings. The ineffective portion, if any, of all hedges is recognized in earnings.
To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we must use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of counterparties.
The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:
- they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MW of electricity or bcf of natural gas),
- they qualify for the normal purchases and sales exception, or
- there is not an active market for the commodity.
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Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. Similarly, certain of our electric capacity and energy contracts are not derivatives due to the lack of an active energy market in Michigan. If active markets for these commodities develop in the future, some of these contracts may qualify as derivatives. For our coal purchase contracts, the resulting mark-to-market impact on earnings could be material. For our electric capacity and energy contracts, we believe that we would be able to apply the normal purchases and sales exception to the majority of these contracts (including the MCV PPA) and, therefore, would not be required to mark these contracts to market.
The MISO began operating the Midwest Energy Market on April 1, 2005. By operating the Midwest Energy Market, the MISO centrally dispatches electricity and transmission service throughout much of the Midwest and provides day-ahead and real-time energy market information. At this time, we believe that the establishment of this market does not represent the development of an active energy market in Michigan, as defined by SFAS No. 133. However, as the Midwest Energy Market matures, we will continue to monitor its activity level and evaluate if an active energy market may exist in Michigan.
Derivative accounting is required for certain contracts used to limit our exposure to interest rate risk, commodity price risk, and foreign exchange risk. The following table summarizes our derivative instruments:
We record the fair value of our interest rate risk contracts, gas supply option contracts, FTRs, and the derivative contracts associated with the MCV Partnership in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets. We include the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The fair value of derivative contracts associated with our equity investments is included in Investments -- Enterprises on our Consolidated Balance Sheets.
INTEREST RATE RISK CONTRACTS: We use interest rate contracts, such as swaps and collars, to hedge the risk associated with future interest payments on variable-rate debt and to reduce the impact of interest rate fluctuations. At December 31, 2005, we have recorded derivative liabilities totaling less than $1 million associated with the fair value of interest rate contracts, effectively hedging long-term variable-rate debt with a notional amount of $24 million. At December 31, 2004, we recorded derivative liabilities totaling $1 million,
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effectively hedging long-term variable-rate debt with a notional amount of $25 million. The notional amount reflects the principal amount of variable-rate debt being fixed.
While all of our interest rate contracts effectively hedge the economic risks associated with variable-rate debt, only some of the contracts qualify as cash flow hedges. At December 31, 2005, we have recorded an unrealized loss of less than $1 million, net of tax, in Accumulated other comprehensive loss relating to the interest rate contracts that we have designated as cash flow hedges. We expect to reclassify this amount as a decrease to earnings during the next 12 months. There was no ineffectiveness associated with any of the interest rate contracts that qualified for cash flow hedge accounting treatment.
GAS SUPPLY OPTION 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. As part of the GCR process, the mark-to-market gains and losses associated with these options are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on the balance sheet as a regulatory asset or liability. At December 31, 2005, we had purchased fixed-priced weather-based gas supply call options and had sold fixed-priced gas supply put options.
FTRS: With the establishment of the Midwest Energy Market, FTRs were established. FTRs are financial instruments that manage price risk related to electricity transmission congestion. An FTR entitles its holder to receive compensation (or, conversely, to remit payment) for congestion-related transmission charges.
DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP:
Long-term gas contracts: The MCV Partnership uses long-term gas contracts to purchase, and manage the cost of, the natural gas it needs to generate electricity and steam. The MCV Partnership believes that certain of these contracts qualify as normal purchases under SFAS No. 133. Accordingly, we have not recognized these contracts at fair value on our Consolidated Balance Sheets at December 31, 2005.
The MCV Partnership also holds certain long-term gas contracts that do not qualify as normal purchases because these contracts contain volume optionality. In addition, as a result of implementing the RCP in January 2005, a significant portion of long-term gas contracts no longer qualify as normal purchases, because the gas will not be used to generate electricity or steam. Accordingly, all of these contracts are accounted for as derivatives, with changes in fair value recorded in earnings each quarter. For the year ended December 31, 2005, we recorded a $149 million gain, before considering tax effects and minority interest, associated with the increase in fair value of these long-term gas contracts. This gain is included in the total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income (Loss). As a result of mark-to-market gains, we have recorded derivative assets totaling $205 million associated with the fair value of long-term gas contracts on our Consolidated Balance Sheets. Because of the volatility of the natural gas market, the MCV Partnership expects future earnings volatility on these contracts, since gains and losses will be recorded each quarter. We expect almost all of these derivative assets to reverse through earnings during 2006 and 2007 as the gas is purchased, with the remainder reversing between 2008 and 2011. Due to the impairment of the MCV Facility, the equity held by the minority interest owners of the MCV Partnership has decreased significantly. Since we have the controlling financial interest in the MCV Partnership, we will assume 100 percent of future losses recognized from the reversal of these assets, not just our proportionate share.
For further details on the RCP, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration Venture."
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Gas Futures and Swaps: The MCV Partnership enters into natural gas futures, options, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas. The MCV Partnership uses these financial instruments to:
- ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam, and
- manage price risk by fixing the price to be paid for natural gas on some of its long-term gas contracts.
At December 31, 2005, the MCV Partnership only held natural gas futures and swaps. Because of increases in the market price of natural gas, the fair value of these contracts increased significantly during 2005. As a result of mark-to-market gains, we have recorded derivative assets totaling $223 million associated with the fair value of these contracts on our Consolidated Balance Sheets. Certain of these contracts, representing $172 million, qualify for cash flow hedge accounting and we record our proportionate share of their mark-to-market gains and losses in Accumulated other comprehensive loss. The remaining contracts, representing $51 million, are not cash flow hedges and their mark-to-market gains and losses are recorded to earnings.
The contracts that qualify as cash flow hedges are used to ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam. At December 31, 2005, we have recorded a cumulative net gain of $56 million, net of tax and minority interest, in Accumulated other comprehensive loss relating to our proportionate share of the cash flow hedges held by the MCV Partnership. Of this balance, we expect to reclassify $15 million, net of tax and minority interest, as an increase to earnings during the next 12 months as the contracts settle, offsetting the costs of gas purchases, with the remainder to be realized through 2009. There was no ineffectiveness associated with any of these cash flow hedges.
The futures and swap contracts that do not qualify as cash flow hedges are used by the MCV Partnership to manage price risk by fixing the price to be paid for natural gas on some of its variable-priced long-term gas contracts. Prior to the implementation of the RCP, these futures and swap contracts were accounted for as cash flow hedges. Since the RCP was implemented in January 2005, these instruments no longer qualify for cash flow hedge accounting. As a result, we reclassified a $29 million gain ($9 million, net of tax and minority interest) to earnings because the hedged forecasted transactions are no longer probable. Additionally, for the year ended December 31, 2005, we recorded an additional $22 million gain associated with the increase in fair value of these instruments. The total gain recognized from these instruments, $51 million before considering tax effects and minority interest, is included in the total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income (Loss). Because of the volatility of the natural gas market, the MCV Partnership expects future earnings volatility on these contracts, since gains and losses will be recorded each quarter. We expect almost all of these futures and swap contracts to be realized during 2006 as the contracts settle, with the remainder to be realized during 2007. For further details on the RCP, see Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration Venture."
The MCV Partnership also engages in cost mitigation activities to offset fixed charges of operating the MCV Facility. These cost mitigation activities may include the use of futures and options contracts to purchase and/or sell natural gas in order to maximize the use of transportation and storage contracts when they are not needed for operation of the MCV Facility. Although these cost mitigation activities do serve to offset fixed monthly charges, these 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. At December 31, 2005, the MCV Partnership did not hold any futures or options for the purpose of these cost mitigation activities.
CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts as a part of activities considered to be an integral part of CMS Energy's ongoing operations. CMS ERM holds certain contracts for the future purchase and sale of electricity and natural gas that will result in physical delivery of the commodity at contractual prices. These forward contracts are generally long-term in nature and are classified as non-trading.
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CMS ERM also uses various financial instruments, including swaps, options, and futures, to manage commodity price risks associated with its forward purchase and sale contracts and with generation assets owned by CMS Energy or its subsidiaries. These financial contracts are classified as trading activities.
In accordance with SFAS No. 133, non-trading and trading contracts that qualify as derivatives are recorded at fair value on our Consolidated Balance Sheets. The resulting assets and liabilities are marked to market each quarter, and changes in fair value are recorded in earnings as a component of Operating Revenue. For trading contracts, these gains and losses are recorded net in accordance with EITF Issue No. 02-03, which we adopted effective January 1, 2003. Contracts that do not meet the definition of a derivative are accounted for as executory contracts (that is, on an accrual basis).
DERIVATIVE CONTRACTS ASSOCIATED WITH EQUITY INVESTMENTS: At December 31, 2005, some of our equity method investees held:
- interest rate contracts that hedged the risk associated with variable-rate debt, and
- foreign exchange contracts that hedged the foreign currency risk associated with payments to be made under operating and maintenance service agreements.
We record our proportionate share of the change in fair value of these contracts in Accumulated other comprehensive loss if the contracts qualify for cash flow hedge accounting; otherwise, we record our share in Earnings from Equity Method Investees.
FOREIGN EXCHANGE DERIVATIVES: At times, we use forward exchange and option contracts to hedge the equity value relating to investments in foreign operations. These contracts limit the risk from currency exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on the hedged investments. At December 31, 2005, we had no outstanding foreign exchange contracts. However, the impact of previous 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 hedged investments. At December 31, 2005, our total foreign currency translation adjustment was a net loss of $313 million, which included a net hedging loss of $26 million, net of tax, related to settled contracts.
CREDIT RISK: Our swaps, options, and forward contracts contain credit risk, which is the risk that counterparties will fail to perform their contractual obligations. We reduce this risk through established credit policies. For each counterparty, we assess credit quality by using credit ratings, financial condition, and other available information. We then establish a credit limit for each counterparty based upon our evaluation of credit quality. We monitor the degree to which we are exposed to potential loss under each contract and take remedial action, if necessary.
CMS ERM and the MCV Partnership enter into contracts primarily with companies in the electric and gas industry. This industry concentration may have an impact on our exposure to credit risk, either positively or negatively, based on how these counterparties are affected by similar changes in economic, weather, or other conditions. CMS ERM and the MCV Partnership typically use industry-standard agreements that allow for netting positive and negative exposures associated with the same counterparty, thereby reducing exposure. These contracts also typically provide for the parties to demand adequate assurance of future performance when there are reasonable grounds for doing so.
The following table illustrates our exposure to potential losses as of December 31, 2005, if each counterparty within this industry concentration failed to perform its contractual obligations. This table includes contracts accounted for as financial instruments. It does not include trade accounts receivable, derivative contracts
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that qualify for the normal purchases and sales exception under SFAS No. 133, or other contracts that are not accounted for as derivatives.
- ------------------------- (a) Exposure is reflected net of payables or derivative liabilities if netting arrangements exist.
(b) Collateral held includes cash and letters of credit received from counterparties.
(c) The remaining balance of our net exposure was from independent natural gas producers/suppliers that do not have published credit ratings. Based on internal credit reviews, we believe that these counterparties are financially strong and creditworthy.
Based on our credit policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance.
7: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after June 30, 2003,
- a DCCP for employees hired on or after September 1, 2005,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) Savings Plan,
- benefits to a select group of management under EISP, and
- health care and life insurance benefits under OPEB.
Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan's assets are not distinguishable by company.
On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of 5 percent of base pay to the existing Employees' Savings Plan. No employee contribution is required in order to receive the plan's employer contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP cost for the period ended December 31, 2005 was less than $1 million.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code; SERP trust earnings are taxable and trust assets are included in consolidated assets. Trust assets were $66 million at December 31, 2005 and $67 million at December 31, 2004. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $74 million at December 31, 2005 and $67 million at December 31, 2004.
401(k): The employer's match for the 401(k) Savings Plan, which was suspended on September 1, 2002 resumed on January 1, 2005. The employer's match is in CMS Energy Common Stock. On September 1, 2005,
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employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages. The total 401(k) Savings Plan cost for the period ended December 31, 2005 was $13 million.
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 2005 and 2004.
EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premium for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was $1 million for the year ended December 31, 2005 and less than $1 million for the year ended December 31, 2004. The ABO for the EISP was $4 million at December 31, 2005 and at December 31, 2004.
OPEB: The OPEB plan covers all regular full-time employees covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least ten full years of applicable continuous service. Regular full-time employees who qualify for a disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs at December 31, 2005 are based on the assumption that costs would increase 10 percent in 2005. The rate of increase is expected to be 10 percent for 2006. The rate of increase is expected to slow to an estimated 5 percent by 2011 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 ABO of the MCV Partnership's postretirement plans was $5 million at December 31, 2005 and 2004. The MCV Partnership's net periodic postretirement health care cost for 2005 and 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. 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 2005 and 2004, and December 31 for 2003. 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 measurement date for the MCV Partnership's plan is December 31 for 2005 and 2004.
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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 reasonableness 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.
Our plan is actuarially equivalent to Medicare Part D and we have incorporated, retroactively, the effects of the subsidy into our financial statements at June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation at 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 implementation resulted in a reduction of OPEB cost of $24 million for 2005 and 2004. The reduction of $24 million includes $6 million for the year ended December 31, 2005 and $7 million for the year ended December 31, 2004 in capitalized OPEB costs.
(b) The Pension Plan's ABO of $1.188 billion exceeded the value of the Pension Plan assets and net balance sheet asset at December 31, 2005. As a result, we recorded a minimum liability of $481 million. Consistent with MPSC guidance, Consumers recognized the cost of their minimum liability as a regulatory asset. Accordingly, our minimum liability includes an intangible asset of $56 million, an accumulated other comprehensive income adjustment of $17 million, net of tax, and a regulatory asset of $399 million. The ABO for the Pension Plan was $1.082 billion at December 31, 2004.
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We remeasured our Pension and OPEB obligations at April 30, 2005 to incorporate the effects of the collective bargaining agreement reached between the Utility Workers Union of America and Consumers. The net periodic pension cost increased $14 million for 2005 and OPEB benefits costs increased $3 million for 2005.
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
- ------------------------- (a) At November 30, 2005, there were zero shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. At November 30, 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.
We contributed $63 million to our OPEB plan in 2005 and we plan to contribute $63 million to our OPEB plan in 2006. We did not contribute to our Pension Plan in 2005 and we plan to contribute $13 million to our Pension plan in 2006.
We have established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor's 500 Index, with lesser allocations to the Standard & Poor's Mid Cap, the Small Cap Indexes and a Foreign Equity Index Fund. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. Annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation.
We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers, and through direct contributions from the non-utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in a Standard & Poor's 500 Index fund. The fixed-income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed-income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.
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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 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 Consumers, as required by SFAS No. 71, we account for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would increase by $25 million.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock are based on decommissioning studies that largely utilize third-party cost estimates.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS: This Interpretation clarified the term "conditional asset retirement obligation" as used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments qualify as a conditional ARO, as defined by FASB Interpretation No. 47. Our asbestos abatement ARO is included in the tables within this Note. This Interpretation is effective for us on December 31, 2005.
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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 ARO liability at January 1, 2004 and December 31, 2004 in the preceding tables reflect the ARO liability as if FASB Interpretation No. 47 had been in effect at that time, as required by the Interpretation. Our financial statements for those periods do not reflect the asbestos abatement ARO. For Consumers, as required by SFAS No. 71, we accounted for the implementation of this Interpretation by recording a regulatory asset instead of a cumulative effect of a change in accounting principle. There was no effect on net income.
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In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and related accounting and ratemaking issues for MPSC-jurisdictional electric and gas utilities. Utilities filed responses to the Order in March 2005; the MPSC Staff and intervenors filed responses in May 2005. On December 5, 2005, the ALJ issued a proposal for decision recommending that the MPSC dismiss the proceeding. Exceptions and replies to exceptions have been filed. We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities. We cannot predict the outcome of the proceeding.
9: INCOME TAXES
CMS Energy and its subsidiaries file a consolidated federal income tax return. Income taxes generally are allocated based on each company's separate taxable income in accordance with the CMS Energy tax sharing agreement.
We utilize deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service life of the related properties. We use ITC to reduce current income taxes payable.
AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2005, we had AMT credit carryforwards in the amount of $204 million that do not expire and tax loss carryforwards in the amount of $1.239 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 $4 million and charitable contribution carryforwards in the amount of $22 million that expire from 2006 through 2009, for which a partial valuation allowance has been provided.
U.S. income taxes are not recorded on the undistributed earnings of foreign subsidiaries that have been or are intended to be reinvested indefinitely. Upon distribution, those earnings may be subject to both U.S. income taxes (adjusted for foreign tax credits or deductions) and withholding taxes payable to various foreign countries. Cumulative undistributed earnings of foreign subsidiaries for which income taxes have not been provided totaled approximately $205 million at December 31, 2005. It is impractical to estimate the amount of unrecognized deferred income taxes or withholding taxes on these undistributed earnings.
The American Jobs Creation Act (AJCA) of 2004 created a one-time opportunity to receive a tax benefit for U.S. corporations that reinvest, in the U.S., dividends received in a year (2005 for CMS Energy) from controlled foreign corporations. During 2005, we repatriated $377 million of foreign earnings that qualified for the tax benefit. The net effect of the repatriated earnings were tax benefits of $45 million in 2005 and $21 million in 2004, which were recorded in income from continuing operations.
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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:
In August 2005, the IRS issued Revenue Ruling 2005-53 and regulations to provide guidance with respect to the use of the "simplified service cost" method of tax accounting. We use this tax accounting method, generally allowed by the IRS under section 263A of the Internal Revenue Code, with respect to the allocation of certain corporate overheads to the tax basis of self-constructed utility assets. Under the IRS guidance, significant issues
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with respect to the application of this method remain unresolved and subject to dispute. However, the effect of the IRS's position may be to require CMS Energy either (1) to repay a portion of previously received tax benefits, or (2) to add back to taxable income, half in each of 2005 and 2006, a significant portion of previously deducted overheads. The impact of this matter on future earnings, cash flows, or our present NOL carryforwards remains uncertain, but could be material. We have recorded a reduction in our NOL carryforwards of $359 million in 2005, and a corresponding reduction in deferred taxes related to property, to reflect the estimated 2005 effect of the new regulation.
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) Because of the small size of the net income in 2003, the effective tax rate is not meaningful.
On December 31, 2005, $25 million of general business credit carryforwards, net of federal income tax, expired for which a full valuation allowance had been provided. The net change in the deferred tax asset of $25 million was offset by the $20 million reduction in the valuation allowance and reversal of unamortized ITC, net of federal income tax, of $5 million.
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 "simplified service cost method" described above is currently under audit by the IRS. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities at December 31, 2005 are adequate for all years.
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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. The Plan has a 5-year term, expiring in May 2009. The Plan includes the following types of awards:
- restricted stock,
- stock options,
- stock appreciation rights,
- phantom shares,
- performance units, and
- management stock purchases.
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.
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 the time of grant. These shares are subject to forfeiture if employment terminates before vesting.
Performance units have an initial value that is 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.
Select participants may elect to receive all or a portion of their incentive payments under the Officer's Incentive Compensation Plan in the form of cash, shares of restricted common stock, shares of restricted stock units, or any combination of these. These participants may also receive awards of additional restricted common stock or restricted stock units, provided the total value of these additional grants does not exceed $2.5 million for any fiscal year.
Under the 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 4,931,130 shares of CMS Energy Common Stock may be issued at December 31, 2005. All grants awarded under this Plan in 2005 were in the form of restricted stock.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes restricted stock and stock option activity:
At December 31, 2005, 878,000 of the 1,682,056 shares of restricted stock outstanding were subject to performance objectives.
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. Compensation expense for restricted stock was $4 million in 2005, $2 million in 2004 and $2 million in 2003. Compensation expense for stock options was $5 million in 2003.
The following table shows the weighted average grant date fair value of restricted stock and stock options:
- -------------------------
(a) There were no stock option grants during 2005 or 2004.
We estimate the fair value of stock options using the Black-Scholes model. We used the following assumptions in the Black-Scholes model:
- ------------------------- (a) There were no stock option grants during 2005 or 2004.
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The following table summarizes our stock options outstanding at December 31, 2005:
The number of stock options exercisable was 3,541,338 at December 31, 2005, 4,778,488 at December 31, 2004, and 5,795,145 at December 31, 2003.
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. Companies must expense this value over the required service period of the awards. This 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 including the timing of expense recognition for share-based awards with terms that accelerate vesting upon retirement. As a result of these clarifications, future compensation costs for share-based awards with accelerated vesting provisions upon retirement will need to be fully expensed by the period in which the employee becomes eligible to retire. At December 31, 2005, unrecognized compensation cost for such share-based awards held by retirement eligible employees was not material.
SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. The modified prospective method applies the recognition provisions to all awards granted or modified after the adoption date of this Statement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective.
The SEC issued SAB No. 107 to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. Also, the SEC issued SAB No. 107 to provide the staff's views regarding the valuation of share-based payments, including assumptions such as expected volatility and expected term. We applied the additional guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R) with no impact on our results of operations.
11: LEASES
Lessee: We lease various assets, including service vehicles, railcars, construction equipment, office furniture, and buildings. 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. In November 2003, we exercised our purchase option under the capital lease agreement for our main headquarters building in Jackson, Michigan.
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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. The following table summarizes our capital and operating lease expenses and sublease income:
- ------------------------- (a) Capital lease obligations totaled $59 million at December 31, 2005.
Minimum annual rental commitments under our non-cancelable leases at December 31, 2005 are:
- -------------------------
(a) Minimum payments have not been reduced by minimum sublease rentals of $1 million due in the future under noncancelable subleases.
(b) In order to obtain permanent financing for the MCV Facility, the MCV Partnership entered into a sale and leaseback 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. At December 31, 2005, finance lease obligations totaled $276 million, which represents the third-party portion of the MCV Partnership's finance lease obligation. Total charges under the MCV Partnership's finance lease obligation were $97 million in 2005 and $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."
Lessor: We have a 44 percent ownership interest in a 31-mile intrastate pipeline that runs from Coldwater Township, Michigan to Hanover Township, Michigan. We lease our interest in the pipeline through a direct finance lease. The lease expires in October 2031, with an annual option to extend the lease.
We sell power, through the Takoradi power plant located in the Republic of Ghana, Africa, under a power purchase agreement with the Volta River Authority. In accordance with SFAS No. 13, we account for this transaction as a direct finance lease. The initial lease term of the agreement expires in 2025.
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The following table summarizes the net investment in direct finance leases at December 31, 2005:
12: PROPERTY, PLANT, AND EQUIPMENT
The following table is a summary of our property, plant, and equipment:
- ------------------------- (a) Capital leases presented in this table are gross amounts. Amortization of capital leases was $54 million in 2005 and $49 million in 2004. Capital lease additions were $12 million and capital lease retirements and adjustments were $7 million at December 31, 2005. Capital lease additions were $3 million and capital lease retirements and adjustments were $1 million at December 31, 2004.
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(b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2005 and $26 million at December 31, 2004, which is not subject to depreciation.
(c) At December 31, 2005, accumulated depreciation, depletion, and amortization is comprised of $4.804 billion from our public utility plant assets and $319 million from other plant assets. At December 31, 2004, accumulated depreciation, depletion, and amortization included $5.665 billion from public utility plant assets and $470 million from other plant assets.
(d) At December 31, 2005, public utility plant additions were $450 million and public utility plant retirements, including other plant adjustments, were $64 million. At December 31, 2004, public utility plant additions were $547 million and public utility plant retirements, including other plant adjustments, were $91 million.
(e) Included in net property, plant and equipment are intangible assets related primarily to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization lives for software development costs are seven and twelve years. The estimated amortization life for leasehold improvements is the life of the lease. Other intangible amortization lives range from 50 to 105 years.
The following tables summarize our intangible assets:
Pretax amortization expense related to these intangible assets was $21 million for the year ended December 31, 2005, $21 million for the year ended December 31, 2004, and $21 million for the year ended December 31, 2003. Amortization of intangible assets is forecasted to range between $13 million and $24 million per year over the next five years.
13: EQUITY METHOD INVESTMENTS
Where ownership is more than 20 percent but less than a majority, we account for certain investments in other companies, partnerships, and joint ventures by the equity method of accounting in accordance with APB Opinion No. 18. Net income from these investments included undistributed earnings of $17 million in 2005, $88 million in 2004, and $41 million in 2003.
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The most significant of these investments are:
- our 50 percent interest in Jorf Lasfar, and
- our 40 percent interest in Taweelah.
If any of our equity method investments have assets or income from continuing operations exceeding 10 percent of our consolidated assets or income, summarized financial data of that subsidiary must be presented in the footnotes. If any of our equity method investments have assets or income from continuing operations exceeding 20 percent of our consolidated assets or income, separate, audited financial statements must be presented as an exhibit to our Form 10-K.
At December 31, 2005, Jorf Lasfar exceeded the 10 percent threshold and no equity method investments exceeded the 20 percent threshold. At December 31, 2004, Taweelah exceeded the 10 percent threshold and Jorf Lasfar exceeded both the 10 percent and 20 percent thresholds.
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 $310 million at December 31, 2005 and $309 million at December 31, 2004. Our share of net income from Jorf Lasfar was $56 million for the year ended December 31, 2005, $63 million for the year ended December 31, 2004, and $60 million for the year ended December 31, 2003.
(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 the years ended December 31, 2005 and 2004.
(c) In August 2004, we sold our investment in SCP.
(d) For 2003, the MCV Partnership was accounted for as an equity method investment but their summarized financial information is not included in these tables. Such information is shown below.
SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER: For 2003, the MCV Partnership was accounted for as an equity method investment. Consumers' 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. Consumers' 2003 obligation to purchase electric capacity from the MCV Partnership
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provided 15 percent of its owned and contracted electric generating capacity. Summarized income statement information of the MCV Partnership follows:
- ------------------------- (a) Revenue from Consumers totaled $514 million in 2003.
(b) Consumers' share of net income was $29 million for the year ended December 31, 2003.
The FMLP is the sole beneficiary of a trust that is the lessor in a long-term direct finance lease with the MCV Partnership. For the year ended December 31, 2003, the FMLP recorded earnings of $32 million related to the direct finance lease.
14: JOINTLY OWNED REGULATED UTILITY FACILITIES
We have investments in jointly owned regulated utility facilities as shown in the following table:
- ------------------------- (a) Net investment is the amount of utility plant in service less accumulated depreciation.
The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant's undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities.
15: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by their products and services. We evaluate performance based upon the net income of each segment. We operate principally in three reportable segments: electric utility, gas utility, and enterprises.
The electric utility segment consists of regulated activities associated with the generation and distribution of electricity in the state of Michigan through our subsidiary, Consumers. The gas utility segment consists of regulated activities associated with the transportation, storage, and distribution of natural gas in the state of Michigan through our subsidiary, Consumers. The enterprises segment consists of:
- investing in, acquiring, developing, constructing, managing, and operating non-utility power generation plants, electric distribution assets, and natural gas facilities in the United States and abroad, and
- providing gas, oil, and electric marketing services to energy users.
Accounting policies of our segments are the same as we describe in the summary of significant accounting policies. Our financial statements reflect the assets, liabilities, revenues, and expenses directly related to the
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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:
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Geographic Areas(c)
- ------------------------- (a) Amounts includes a portion of Consumers' other common assets attributable to both the electric and gas utility businesses.
(b) Amounts include electric restructuring implementation plan, purchase of nuclear fuel, and capital lease additions. Amounts also include a portion of Consumers' capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.
(c) Revenues are based on the country location of customers.
16: CONSOLIDATION OF VARIABLE INTEREST ENTITIES
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. Therefore, we consolidated these partnerships into our consolidated financial statements as of and for the years ended December 31, 2005 and December 31, 2004.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
These partnerships have third-party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $224 million at December 31, 2005 and $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, 2005, the MCV Partnership had total assets of $1.318 billion and a net loss of $917 million for the year. At December 31, 2004, the MCV Partnership had total assets of $1.980 billion and a net loss of $24 million for the year.
We are the primary beneficiary of three other variable interest entities. We have 50 percent partnership interests each in the T.E.S. Filer City Station Limited Partnership, the Grayling Generating Station Limited Partnership, and the Genesee Power Station Limited Partnership. Additionally, we have operating and management contracts and are the primary purchaser of power from each partnership through long-term power purchase agreements. Collectively, these interests make us the primary beneficiary of these entities. Therefore, we consolidated these partnerships into our consolidated financial statements for all periods presented. These partnerships have third-party obligations totaling $108 million at December 31, 2005 and $116 million at December 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $163 million at December 31, 2005 and $168 million at December 31, 2004. Other than through outstanding letters of credit and guarantees of $5 million, the creditors of these partnerships do not have recourse to the general credit of CMS Energy.
Additionally, we hold interests in variable interest entities in which we are not the primary beneficiary. The following chart details our involvement in these entities at December 31, 2005:
Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $127 million, and letters of credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling $45 million.
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CMS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
17: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
- ------------------------- (a) Net of tax.
(b) Sum of the quarters may not equal the annual earnings per share due to changes in shares outstanding.
(c) Based on New York Stock Exchange -- Composite transactions.
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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, 2005 and 2004, 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, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a 49% owned variable interest entity which has been consolidated in 2005 and 2004 and accounted for under the equity method of accounting in 2003. We also did not audit the financial statements of Jorf Lasfar Energy Company S.C.A. (which represents an investment accounted for under the equity method of accounting), as of December 31, 2004 and for each of the two years in the period ended December 31, 2004. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for the periods indicated above for Midland Cogeneration Venture Limited Partnership and Jorf Lasfar Energy Company S.C.A., respectively, is based solely on the reports of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CMS Energy Corporation at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 8 to the consolidated financial statements, in 2005, the Company adopted Financial Accounting Standards Board (FASB) interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations". As discussed in Note 16 to the consolidated financial statements, in 2004, the Company adopted Revised 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 and 8 to the consolidated financial statements, in 2003, the Company adopted the provisions of EITF Issue No. 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts" and of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations".
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, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an adverse opinion on the effectiveness of the Company's internal control over financial reporting because of the existence of a material weakness.
/s/ Ernst & Young LLP
Detroit, Michigan February 22, 2006
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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 integrated audits of Midland Cogeneration Venture Limited Partnership's 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 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 consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership (a Michigan Limited Partnership) and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9(A), that the Partnership maintained effective internal control over financial reporting as of December 31, 2005 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, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control -- Integrated Framework issued by the COSO. The Partnership'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 the Partnership'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, 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
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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 20, 2006
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REPORT OF INDEPENDENT AUDITORS
To the Management Committee and Shareholders of Jorf Lasfar ENERGY COMPANY S.C.A. (JLEC) B.P. 99 -- Sidi Bouzid El Jadida, Morocco
We have audited the balance sheet of Jorf Lasfar Energy Company S.C.A. (the Company) as of December 31, 2005 and the related statements of income, shareholders' equity, and cash flows for the year 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 audit. The financial statements of Jorf Lasfar Energy Company S.C.A. for the year ended December 31, 2004 and 2003 were audited by other auditors whose report dated February 11, 2005, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2005 financial statements referred to above present fairly, in all material respects, the financial position of Jorf Lasfar Energy Company SCA at December 31, 2005, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
/s/ ERNST & YOUNG
Casablanca, February 10th, 2006
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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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CMS Energy Corporation
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[CONSUMERS ENERGY LOGO]
2005 CONSOLIDATED FINANCIAL STATEMENTS
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CONSUMERS ENERGY COMPANY
SELECTED FINANCIAL INFORMATION
- ------------------------- (a) See Notes 1 and 3 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 years ended December 31, 2005 and 2004. These partnerships had third party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004.
(c) Effective December 31, 2003, Trust Preferred Securities are classified on 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 serving 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 and operate principally in two business segments: electric utility and gas utility. Our electric utility operations include the generation, purchase, distribution, and sale of electricity. Our gas utility operations include the purchase, transportation, storage, distribution, and sale of natural gas.
We earn our revenue and generate cash from operations by providing electric and natural gas utility services, electric power generation, gas 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,
- energy commodity prices,
- interest rates, and
- our debt credit rating.
During the past two years, our business strategy has involved improving our balance sheet and maintaining focus on our core strength: utility operations and service. In 2005, we continued our focus on utility operations and meeting customer commitments.
We are focused on growing the equity base of our company and have been refinancing our debt to reduce interest rate costs. In 2005, we retired higher-interest rate debt through the use of proceeds from the issuance of $875 million of FMB. We also received cash contributions from CMS Energy of $700 million in 2005. In January 2006, we received an additional $100 million cash contribution from CMS Energy and in February 2006, we extinguished, through a legal defeasance, $129 million of 9 percent notes.
Despite this progress, working capital and cash flow continue to be a challenge for us. Natural gas prices continue to increase substantially. Although our natural gas purchases are recoverable from our utility customers, as gas prices increase, the amount we pay for natural gas will require additional liquidity due to the lag in cost recoveries.
In addition to causing working capital issues for us, rising natural gas prices caused the MCV Partnership to reevaluate the economics of operating the MCV Facility and to determine that an impairment charge of $1.159 billion was required in September 2005. As a result, our 2005 net income was reduced by $369 million, after accounting for minority interest and tax effects. We further reduced our 2005 net income by $16 million by impairing certain other assets on our Consolidated Balance Sheets related to the MCV Partnership. For additional details regarding the impairment, see Note 2, Asset Impairment Charges.
Projected future gas prices continue to threaten the continuing viability of the MCV Facility. We are evaluating various alternatives in order to develop a new long-term strategy with respect to the MCV Facility. The MCV Partnership is working aggressively to reduce costs, improve operations, and enhance cash flows. However, continued high gas prices could result in a further impairment of our ownership interests in the MCV Partnership and the FMLP. CE-3
Going forward, our strategy will continue to focus on:
- managing cash flow issues caused by rising gas prices,
- maintaining and growing earnings, and
- investing in our utility system to enable us to meet our commitments to customers and comply with increasing environmental performance standards.
As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been further hampered by recent negative developments in Michigan's automotive industry and limited growth in the non-automotive and health services sectors of our economy.
These negative effects will be offset somewhat by the reduction we are experiencing in ROA load in our service territory. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of our total distribution load. It is, however, difficult to predict future ROA customer trends.
FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-K and other written and oral statements that we make contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Our intention with the use of words such as "may," "could," "anticipates," "believes," "estimates," "expects," "intends," "plans," and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict and/or control:
- 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, including availability of financing to Consumers, CMS Energy, or any of their affiliates and the energy industry,
- market perception of the energy industry, Consumers, CMS Energy, or any of their affiliates,
- credit ratings of Consumers, CMS Energy, or any of their affiliates,
- factors affecting utility and diversified energy operations such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints,
- international, national, regional, and local economic, competitive, and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions,
- potentially adverse regulatory treatment and/or regulatory lag concerning a number of significant questions presently before the MPSC including:
- recovery of Clean Air Act 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,
- adequate and timely recovery of additional electric and gas rate-based investments,
- adequate and timely recovery of higher MISO energy costs, and
- recovery of future Stranded Costs incurred due to customers choosing alternative energy suppliers,
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- the impact of adverse natural gas prices on the MCV Partnership and FMLP investments, regulatory decisions that limit recovery of capacity and fixed energy payments, and our ability to develop a new long-term strategy with respect to the MCV Facility,
- federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of our market-based sales authorizations in wholesale power markets without price restrictions,
- energy markets, including availability of capacity and the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity and certain related products due to lower or higher demand, shortages, transportation problems, or other developments,
- our ability to collect accounts receivable from our gas customers due to high natural gas prices,
- the GAAP requirement that we utilize mark-to-market accounting on certain energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods and could add to earnings volatility,
- the effect on our electric utility of the direct and indirect impacts of the continued economic downturn experienced by our automotive and automotive parts manufacturing customers,
- potential disruption or interruption of facilities or operations due to accidents or terrorism, and the ability to obtain or maintain insurance coverage for such events,
- nuclear power plant performance, decommissioning, policies, procedures, incidents, and regulation, including the availability of spent nuclear fuel storage,
- technological developments in energy production, delivery, and usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or policies,
- changes in tax laws or new IRS interpretations of existing tax laws,
- 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.
For additional information regarding these and other uncertainties, see Item 1A. Risk Factors, and Note 3, Contingencies.
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RESULTS OF OPERATIONS
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER
For 2005, our net loss available to our common stockholder was $98 million, compared to net income available to our common stockholder of $277 million for 2004. The decrease is primarily due to an impairment charge to property, plant, and equipment at the MCV Partnership to reflect the excess of the carrying value of these assets over their estimated fair value. For additional details on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges. The decrease also reflects a reduction in net income from our electric utility, as higher operating and maintenance costs exceeded higher, weather-driven sales to our residential customers. Additionally, the decrease reflects a reduction in net income from our gas utility, as higher operating and maintenance costs exceeded the benefits derived from the increase in revenue resulting from the gas rates surcharge authorized by the MPSC in October of 2004. Partially offsetting these decreases is an increase in the fair value of certain long-term gas contracts and financial hedges at the MCV Partnership.
Specific changes to net income (loss) available to our common stockholder for 2005 versus 2004 are:
For 2004, our net income available to our common stockholder was $277 million, compared to $194 million of net income available to our common stockholder for 2003. The increase is primarily due to lower operating expenses, reflecting the MPSC's approval for recovery of stranded costs for 2002 and 2003, and the deferral of electric depreciation expense on our excess capital expenditures as permitted by the Customer Choice Act. Also
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contributing to the increase was $73 million of additional return on capital expenditures in excess of our depreciation base as permitted by the Customer Choice Act. Partially offsetting these increases are higher interest charges primarily due to a reduction in capitalized interest on the Clean Air Act costs incurred during the period June 2000 through December 2003, and a $22 million decrease in electric delivery revenue primarily due to tariff revenue reductions, customers choosing alternative electric suppliers, and milder summer temperatures.
Specific changes to net income available to our common stockholder for 2004 versus 2003 are:
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ELECTRIC UTILITY RESULTS OF OPERATIONS
ELECTRIC DELIVERIES: For 2005, electric deliveries to end-use customers increased 1.3 billion kWh or 3.4 percent versus 2004. The corresponding increase in electric delivery revenue was due to increased sales to residential customers, reflecting warmer summer weather and increased surcharge revenue from all customers.
On July 1, 2004, Consumers started collecting a surcharge to recover costs incurred in the transition to customer choice. This surcharge increased electric delivery revenue by $13 million in 2005 versus 2004. Surcharge revenue related to the recovery of security costs and stranded costs increased electric delivery revenue by an additional $10 million in 2005 versus 2004.
For 2004, electric deliveries to end-use customers increased 0.1 billion kWh or 0.4 percent versus 2003. Despite the increase in electric deliveries, electric delivery revenue decreased due to the milder summer temperatures' negative impact on 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 in 2004 versus 2003.
POWER SUPPLY COSTS AND RELATED REVENUE: Our recovery of power supply costs was capped for our residential customers until January 1, 2006. For 2005, our underrecovery of power costs allocated to these capped customers increased by $76 million versus 2004. Power supply-related costs increased in 2005 primarily due to higher coal costs and higher purchased power costs due to higher weather-driven sales.
Partially offsetting these underrecoveries were benefits from the deferral of transmission and nitrogen oxide allowance expenditures related to our capped customers. To the extent these costs were not fully recoverable due to the application of rate caps, we deferred these costs for recovery under Public Act 141. In December 2005, the MPSC approved the recovery of these costs. For additional details, see "Electric Business Uncertainties -- Competition and Regulatory Restructuring" within this MD&A. For 2005, deferrals of these costs increased by $30 million versus 2004.
For 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
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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.
OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: For 2005, other operating expenses increased $139 million, other income increased $4 million, and non-commodity revenue increased $4 million versus 2004.
The increase in other operating expenses reflects higher depreciation and amortization expense, higher pension and benefit expense, and higher underrecovery expense related to the MCV PPA, offset partially by our direct savings from the RCP. Depreciation and amortization expense increased primarily due to a reduction in 2004 expense to reflect an MPSC order allowing recovery of $57 million of Stranded Costs. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005.
In 1992, a liability was established for estimated future underrecoveries of power supply costs under the MCV PPA. In 2004, a portion of the cash underrecoveries continued to reduce this liability until its depletion in December. In 2005, all cash underrecoveries were expensed directly to income. Consequently, the cost associated with the MCV PPA cash underrecoveries increased operating expense $30 million for 2005 versus 2004. Offsetting this increased operating expense were the savings from the RCP approved by the MPSC in January 2005.
The RCP allows us to dispatch the MCV Facility on the basis of natural gas prices, which will reduce the MCV Facility's annual production of electricity and, as a result, reduce the MCV Facility's consumption of natural gas. The MCV Facility's fuel cost savings are first used to offset the cost of replacement power and fund a renewable energy program. Remaining savings are split between us and the MCV Partnership. Our direct savings were shared 50 percent with customers in 2005 and will be shared 70 percent thereafter. Our direct savings, after allocating an equal portion to customers, was $32 million for 2005.
For 2005, the increase in other income was primarily due to higher interest income on short-term cash investments versus 2004, offset partially by expenses associated with the early retirement of debt. The increase in non-commodity revenue was primarily due to higher transmission services revenue versus 2004.
For 2004, other operating expenses decreased $82 million, other income increased $12 million, and non-commodity revenue decreased $3 million versus 2003. Other operating expenses decreased due to reduced depreciation, pension, and benefit expenses. The decrease in depreciation expense reflects an MPSC order allowing recovery of $57 million of Stranded Costs incurred from 2002 to 2003. 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. 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.
REGULATORY RETURN ON CAPITAL EXPENDITURES AND RELATED CAPITALIZED INTEREST: For 2005, the return on capital expenditures in excess of our depreciation base, net of related capitalized interest, decreased income by $30 million versus 2004. The decrease reflects the impact of the MPSC's December 2005 order authorizing recovery of and a return on our capital expenditures in excess of our depreciation base.
For 2004, the return on capital expenditures in excess of our depreciation base, net of related capitalized interest, increased income by $77 million versus 2003. The increase reflects a $72 million return on Clean Air Act costs incurred during the period June 2000 through December 2003 to reflect an interpretation of the Customer Choice Act by the MPSC in a rate order involving Detroit Edison.
GENERAL TAXES: For 2005, general taxes decreased primarily due to lower property tax expense. Lower property tax expense in 2005 reflects the use of revised tax tables by several of Consumers' taxing authorities and, separately, other property tax refunds.
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For 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.
INTEREST CHARGES: For 2005, interest charges reflect a 31 basis point reduction in the average rate of interest on our debt. This benefit was offset partially by higher average debt levels versus 2004.
For 2004, interest charges reflect higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest on our debt versus 2003.
INCOME TAXES: For 2005, income taxes decreased primarily due to lower earnings versus 2004, offset partially by a $2 million increase to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders.
For 2004, income taxes increased primarily due to increased earnings from the electric utility versus 2003. The increase also reflects $2 million related to the tax treatment of items related to property, plant, and equipment as required by past MPSC orders. This increase was offset partially by the benefits received from Part D of the Medicare Prescription Drug, Improvement and Modernization Act, which was signed into law in December 2003.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF TAX EXPENSE: The measurement date for all of Consumers' plans is November 30 for 2005 and 2004, and December 31 for 2003. As a result of the measurement date change, in 2004 we recorded a $1 million, net of tax, cumulative effect adjustment as a decrease to earnings.
GAS UTILITY RESULTS OF OPERATIONS
GAS DELIVERIES: For 2005, gas delivery revenues reflect lower deliveries to our customers versus 2004. Gas deliveries, including miscellaneous transportation to end-use customers, decreased 2.4 bcf or 0.7 percent.
For 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. The decrease in gas delivery revenues was offset partially by a $12 million increase in gas revenues associated with our annual 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 annual increase of $58 million through a two-year surcharge. As a result of these orders, gas revenues increased $28 million for 2005 versus 2004 and $28 million for 2004 versus 2003.
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUE AND OTHER INCOME: For 2005, income from gas wholesale and retail services and other gas revenue increased versus 2004. Other income increased primarily due
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to higher interest income on short-term cash investments, offset partially by expenses associated with the early retirement of debt, versus 2004.
For 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. Other income remained consistent with 2003.
OPERATION AND MAINTENANCE: For 2005, operation and maintenance expenses increased primarily due to increases in benefit costs and additional safety, reliability, and customer service expenses versus 2004. Pension and benefit expense increased primarily due to changes in actuarial assumptions and the remeasurement of our pension and OPEB plans to reflect the new collective bargaining agreement between the Utility Workers Union of America and Consumers. Benefit expense also reflects the reinstatement of the employer matching contribution to our 401(k) plan in January 2005.
For 2004, operation and maintenance expenses decreased primarily due to reduced pension and benefit expense of $23 million versus 2003. 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 increased expenditures on safety, reliability, and customer service.
GENERAL TAXES: For 2005, general taxes decreased primarily due to lower property tax expense versus 2004. Lower property tax expense in 2005 reflects an increased use of revised tax tables by several of Consumers' taxing authorities, and separately, other property tax refunds. For 2004, general taxes increased due to the absence of an 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.
DEPRECIATION: For 2005, depreciation expense increased primarily due to higher plant in service versus 2004. For 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.
INTEREST CHARGES: For 2005, interest charges reflect a 31 basis point reduction in the average rate of interest on our debt and higher average debt levels versus 2004.
For 2004, interest charges reflect higher average debt levels, offset partially by a 46 basis point reduction in the average rate of interest on our debt versus 2003.
INCOME TAXES: For 2005, income taxes decreased due to lower earnings versus 2004. This decrease was offset by $5 million to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders, and the write-off of general business credits expected to expire in 2005.
For 2004, income taxes increased due to increased earnings versus 2003. This increase was offset by $7 million to reflect the tax treatment of items related to property, plant, and equipment as required by past MPSC orders, and by Part D of the Medicare Prescription Drug, Improvement and Modernization Act, which was signed into law in December 2003.
OTHER RESULTS OF OPERATIONS
For 2005, other operations decreased net income by $299 million, a decrease of $283 million versus 2004. The change is primarily due to a $285 million decrease in earnings related to our ownership interest in the MCV Partnership. In September 2005, the MCV Partnership recorded an impairment charge to property, plant, and equipment to reflect the excess of the carrying value of these assets over their estimated fair value. Partially
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offsetting the impairment charge is an increase in the fair value of certain long term gas contracts and related financial hedges at the MCV Partnership.
For 2004, other operations decreased net income by $16 million, a decrease of $5 million in income versus 2003. The change is primarily due to a decrease in earnings related to our ownership interest in the MCV Partnership due to non-recoverable fuel costs incurred at the MCV Facility.
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 long-lived assets and equity method investments,
- accounting for the effects of industry regulation,
- accounting for financial and derivative instruments and market risk information,
- 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. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, and contingencies. For example, we estimate the rate of return on plan assets and the cost of future health-care benefits to determine our annual pension and other postretirement benefit costs. 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 a 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 the history and specifics of each matter. Significant contingencies are discussed in the "Outlook" section included in this MD&A.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. We periodically perform tests of impairment if certain conditions that are other than temporary exist that may indicate the carrying value may not be recoverable. Of our total assets, recorded at $13.157 billion at December 3l, 2005, 56 percent represent long-lived assets and equity method investments that are subject to this type of analysis. We base our evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- regulatory and political environments,
- state and federal regulatory and political environments,
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- 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. If the fair value is less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded.
Our assessments of fair value using these valuation methodologies represent our best estimates at the time of the reviews and are consistent with our internal planning. The estimates we use can change over time, which could have a material impact on our financial statements.
For additional details on asset impairments, see Note 2, Asset Impairment Charges.
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions affect the timing and recognition of revenues and expenses. We use SFAS No. 71 to account for the effects of these regulatory decisions. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity.
For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate such expenses will be recovered in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate they will require that such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. At December 31, 2005, we had $1.800 billion recorded as regulatory assets and $1.753 billion recorded as regulatory liabilities.
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. These criteria are complex and significant judgment is often required in applying the criteria to specific contracts. If a contract is a derivative, it is recorded on the balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. For additional details on accounting for derivatives, see Note 5, Financial and Derivative Instruments. CE-13
To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we must use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. Changes in forward prices or volatilities could significantly change the calculated fair value of our derivative contracts. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of counterparties.
The following table summarizes the interest rate and volatility rate assumptions we used to value these contracts at December 31, 2005:
The types of contracts we typically classify as derivative instruments are interest rate swaps, gas supply options, certain long-term gas contracts, and gas fuel futures, swaps, and options. The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:
- they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MW of electricity or bcf of natural gas),
- they qualify for the normal purchases and sales exception, or
- there is not an active market for the commodity.
Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. Similarly, our electric capacity and energy contracts are not derivatives due to the lack of an active energy market in Michigan. If active markets for these commodities develop in the future, some of these contracts may qualify as derivatives. For our coal purchase contracts, the resulting mark-to-market impact on earnings could be material. For our electric capacity and energy contracts, we believe that we would be able to apply the normal purchases and sales exception, and, therefore, would not be required to mark these contracts to market.
Establishment of the Midwest Energy Market: The MISO began operating the Midwest Energy Market on April 1, 2005. By operating the Midwest Energy Market, the MISO centrally dispatches electricity and transmission service throughout much of the Midwest and provides day-ahead and real-time energy market information. At this time, we believe that the establishment of this market does not represent the development of an active energy market in Michigan, as defined by SFAS No. 133. However, as the Midwest Energy Market matures, we will continue to monitor its activity level and evaluate if an active energy market may exist in Michigan.
Implementation of the RCP: As a result of implementing the RCP in January 2005, a significant portion of the MCV Partnership's long-term gas contracts no longer qualify as normal purchases because the gas will not be used to generate electricity or steam. Accordingly, these contracts are accounted for as derivatives, with changes in fair value recorded in earnings each quarter. Additionally, certain of the MCV Partnership's natural gas futures and swap contracts, which are used to hedge variable-priced long-term gas contracts, no longer qualify for cash flow hedge accounting and we record any changes in their fair value in earnings each quarter. As a result of
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recording the changes in fair value of these long-term gas contracts and the related futures and swaps to earnings, the MCV Partnership has recognized the following gains and losses in 2005:
These gains and losses, shown before consideration of tax effects and minority interest, are included in the total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income (Loss). Because of the volatility of the natural gas market, the MCV Partnership expects future earnings volatility on both the long-term gas contracts and the futures and swap contracts, since gains and losses will be recorded each quarter. As a result of mark-to-market gains, we have recorded derivative assets totaling $256 million associated with the fair value of these contracts on our Consolidated Balance Sheets. We expect almost all of these assets to reverse through earnings during 2006 and 2007 as the gas is purchased and the futures and swaps settle, with the remainder reversing between 2008 and 2011. Due to the impairment of the MCV Facility, the equity held by the minority interest owners of the MCV Partnership has decreased significantly. Since we have the controlling financial interest in the MCV Partnership, we will assume 100 percent of future losses recognized from the reversal of these assets, not just our proportionate share.
MARKET RISK INFORMATION: We are exposed to market risks including, but not limited to, changes in commodity prices, interest rates, and equity security prices. We may use various contracts to manage these risks, including options, futures, swaps, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of both:
- an executive oversight committee consisting of senior management representatives, and
- a risk committee consisting of business unit managers.
Our intention is that any increases or decreases in the value of these contracts will be offset by an opposite change in the value of the item at risk.
These contracts contain credit risk, which is the risk that counterparties, primarily financial institutions and energy marketers, will fail to perform their contractual obligations. We reduce this risk through established credit policies, which include performing financial credit reviews of our counterparties. We determine our counterparties' credit quality using a number of factors, including credit ratings, disclosed financial condition, and collateral requirements. If terms permit, we use standard agreements that allow us to net positive and negative exposures associated with the same counterparty. Based on these policies and our current exposures, we do not expect a material adverse effect on our financial position or earnings as a result of counterparty nonperformance.
The following risk sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical unfavorable change in market rates or prices of 10 percent. Changes in excess of the amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift used for the analyses.
Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital.
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Interest Rate Risk Sensitivity Analysis (assuming an unfavorable change in market interest rates of 10 percent):
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(a) Fair value exposure could only be realized if we repurchased all of our fixed-rate financing.
Commodity Price Risk: Operating in the energy industry, we are exposed to commodity price risk, which arises from fluctuations in the price of electricity, natural gas, coal, and other commodities. Commodity prices are influenced by a number of factors, including weather, changes in supply and demand, and liquidity of commodity markets. In order to manage commodity price risk, we enter into various non-trading derivative contracts, such as gas supply call and put options, long-term gas contracts, gas futures, and gas swaps. For additional details on these contracts, see Note 5, Financial and Derivative Instruments.
Commodity Price Risk Sensitivity Analysis (assuming an unfavorable change in market prices of 10 percent):
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(a) The increased potential reduction in fair value for the MCV Partnership's long-term gas contracts is due to the increased number of contracts accounted for as derivatives as a result of the RCP.
Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available-for-sale investments.
Investment Securities Price Risk Sensitivity Analysis (assuming an unfavorable change in market prices of 10 percent):
We maintain trust funds, as required by the NRC, for the purpose of funding certain costs of nuclear plant decommissioning. At December 31, 2005 and 2004, 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 our consolidated earnings or cash flows.
For additional details on market risk and derivative activities, see Note 5, Financial and Derivative Instruments.
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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. On September 1, 2005, we implemented the DCCP.
The DCCP provides an employer contribution of 5 percent of base pay to the existing Employees' Savings Plan. No employee contribution is required in order to receive the plan's employer cash contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. We use SFAS No. 87 to account for pension costs.
401(k): We resumed the employer's match in CMS Energy Common Stock in our 401(k) Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages.
OPEB: We provide postretirement health and life benefits under our OPEB plan to substantially all our retired employees. We use SFAS No. 106 to account for other postretirement benefit costs.
Liabilities for both pension and OPEB are recorded on the balance sheet at the present value of their future obligations, net of any plan assets. The calculation of the liabilities and associated expenses requires the expertise of actuaries. Many assumptions are made, including:
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
Any change in these assumptions can change significantly the liability and associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:
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 8.50 percent to 8.25 percent) would increase estimated pension cost for 2006 by $3 million. Lowering the discount rate by 0.25 percent (from 5.75 percent to 5.50 percent) would increase estimated pension cost for 2006 by $1 million.
For additional details on postretirement benefits, see Note 6, Retirement Benefits.
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ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, as clarified by FASB Interpretation No. 47, requires companies to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets, including our nuclear plants, at the end of their useful lives. As required by SFAS No. 71, we accounted for the implementation of this standard by recording regulatory assets and liabilities instead of a cumulative effect of a change in accounting principle.
The fair value of ARO liabilities has been calculated using an expected present value technique. This technique reflects assumptions such as costs, inflation, and profit margin that third parties would consider to assume the settlement of the obligation. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, gas transmission and electric and gas distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. In addition, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates. For additional details on ARO, see Note 7, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission, or remove from services, our Big Rock and Palisades nuclear plants. Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent landscape,
- all contaminated equipment and material will be removed and disposed of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning 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.
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. 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 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. At this time, we cannot determine what impact a license renewal for the Palisades plant will have on decommissioning costs or the adequacy of funding. For additional details, see
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Note 3, Contingencies, "Other Electric Contingencies -- Nuclear Plant Decommissioning" and "Nuclear Matters," and Note 7, Asset Retirement Obligations.
RELATED PARTY TRANSACTIONS
We enter into a number of significant transactions with related parties. These transactions include:
- issuance of trust preferred securities with Consumers' affiliated companies,
- purchase and sale of electricity from and to Enterprises,
- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,
- payment of parent company overhead costs to CMS Energy, and
- investment in CMS Energy Common Stock.
Transactions involving CMS Energy and its affiliates generally are based on regulated prices, market prices, or competitive bidding. Transactions involving the power supply purchases from certain affiliates of Enterprises are based upon avoided costs under PURPA and competitive bidding. The payment of parent company overhead costs is based on the use of accepted industry allocation methodologies.
For additional details on related party transactions, see Note 1, Corporate Structure and Accounting Policies, "Related Party Transactions," and Note 3, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our:
- results of operations,
- capital expenditures,
- contractual obligations,
- debt maturities,
- working capital needs, and
- collateral requirements.
During the summer months, we purchase natural gas and store it for resale primarily during the winter heating season. In 2005, the market price for natural gas increased substantially. Although our prudent natural gas purchases are recoverable from our customers, as gas prices increase, the amount paid for natural gas stored as inventory requires additional liquidity due to the timing of the cost recoveries. We have credit agreements with our commodity suppliers and those agreements contain terms that have resulted in margin calls. Additional margin calls or other credit support may be required if agency ratings are lowered or if market conditions remain unfavorable relative to our obligations to those parties.
Our current financial plan includes controlling operating expenses and capital expenditures and evaluating market conditions for financing opportunities. Due to the adverse impact of the MCV Partnership asset impairment charge recorded in September 2005, our ability to issue FMB as primary obligations or as collateral for financing is expected to be limited to $298 million through September 30, 2006. After September 30, 2006, our ability to issue FMB in excess of $298 million is based on achieving a two-times FMB interest coverage ratio.
We believe the following items will be sufficient to meet our liquidity needs:
- our current level of cash and revolving credit facilities,
- our ability to access junior secured and unsecured borrowing capacity in the capital markets, and
- anticipated cash flows from operating and investing activities.
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CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2005, $599 million consolidated cash was on hand, which includes $183 million of restricted cash and restricted short-term investments and $361 million from the entities consolidated pursuant to FASB Interpretation No. 46. For additional details, see Note 14, Consolidation of Variable Interest Entities.
SUMMARY OF CASH FLOWS:
OPERATING ACTIVITIES:
2005: Net cash provided by operating activities increased $47 million in 2005. Cash provided by operations resulted primarily from a decrease in prepaid gas margin call costs, an increase in tax liabilities related to a recent IRS ruling regarding the "simplified service cost" method of tax accounting, the positive effect of rising gas prices on accounts payable and MCV gas supplier funds on deposit, and other timing differences. These increases were offset partially by the negative effect of rising gas prices on accounts receivable and inventories.
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.
INVESTING ACTIVITIES:
2005: Net cash used in investing activities increased $147 million in 2005 primarily due to an increase in restricted cash and restricted short-term investments of $159 million. The increase in restricted cash and restricted short-term investments was due to a deposit made with a trustee for extinguishing the current portion of long-term debt -- related parties.
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.
FINANCING ACTIVITIES:
2005: Net cash provided by financing activities increased $394 million in 2005 due to an increase of $450 million in stockholder's contributions from the parent and an increase in cash due to lower payments on borrowings of $16 million, offset by an increase in common stock dividends payments of $87 million.
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.
For additional details on long-term debt activity, see Note 4, Financings and Capitalization.
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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 2006.
CONTRACTUAL OBLIGATIONS AT DECEMBER 31, 2005
Long-Term Debt: The amounts in the preceding table represent the principal amounts due on outstanding debt obligations, current and long-term, at December 31, 2005. For additional details on long-term debt, see Note 4, Financings and Capitalization.
Interest payments on long-term debt: The amounts in the preceding table 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, 2005.
Capital and finance leases: The amounts in the preceding table represent the minimum lease payments payable under our capital and finance leases. They are comprised mainly of the leased portion of the MCV Facility, leased service vehicles, leased office furniture, and certain power purchase agreements.
Interest payments on capital and finance leases: The amounts in the preceding table represent imputed interest in the capital leases and currently scheduled interest payments on the finance leases.
Operating Leases: The amounts in the preceding table 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: The amounts in the preceding table represent long-term contracts for purchase of commodities and services. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include:
- natural gas,
- electricity, and
- coal and associated transportation.
Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants' availability or deliverability. These payments will approximate $12 million per month during 2006. 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
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power supply costs, see "Electric Utility Results of Operations" within this MD&A and Note 3, Contingencies, "Electric Rate Matters -- Power Supply Costs."
Long-term Service Agreements: The amounts in the preceding table represent obligations of the MCV Partnership, primarily the cost of the current MCV Facility maintenance service agreements and cost of spare parts.
REVOLVING CREDIT FACILITIES: At December 31, 2005, we had $464 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 4, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: We enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, letters of credit and surety bonds.
We enter into agreements containing indemnifications standard in the industry and indemnifications specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually agreements to reimburse other companies if those companies incur losses due to third-party claims or breach of contract terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a third party. Letters of credit substitute the bank's credit for ours and reduce credit risk for the third-party beneficiary. We monitor these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. For additional details on these arrangements, see Note 3, Contingencies, "Other Contingencies -- FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others."
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we may sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for securitized financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see Note 4, Financings and Capitalization.
DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4, Financings and Capitalization.
DEBT CREDIT RATING: In November 2005, S&P placed CMS Energy's and Consumers' debt credit ratings on CreditWatch with negative implications. In January 2006, S&P removed the ratings from CreditWatch with negative implications and affirmed CMS Energy's and Consumers' debt credit ratings with a stable outlook.
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CAPITAL EXPENDITURES: We estimate that we will make the following capital expenditures, including new lease commitments, by expenditure type and by business segments during 2006 through 2008. We prepare these estimates for planning purposes and may revise them.
- ------------------------- (a) These amounts include estimates for capital expenditures that may be required by revisions to the Clean Air Act's national air quality standards.
(b) These amounts include estimates for capital expenditures related to information technology projects, facility improvements, and vehicle leasing.
OUTLOOK
ELECTRIC BUSINESS OUTLOOK
GROWTH: Summer 2005 temperatures were higher than historical averages, leading to increased demand from electric customers. As a result, growth in electric deliveries in 2005, excluding transactions with other wholesale market participants and other utilities, was more than three percent. In 2006, we project electric deliveries to be about flat compared to the levels experienced in 2005. This short-term outlook for 2006 assumes a recovering economy 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. However, such growth is dependent on a modestly growing customer base and recovery of the Michigan 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 or contraction of manufacturing facilities.
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 requested an annual increase in revenues of approximately $320 million, which we revised in August 2005 to approximately $197 million. The primary reasons for our electric rate case were increased system maintenance and improvement costs, Clean Air Act-related expenditures, and employee pension costs. In December 2005, the MPSC issued an order that allows a base rate increase in the annual amount of $86 million, establishes an 11.15 percent authorized return on equity, and recognizes the impacts on our projected equity investment (infusions and retained earnings) in 2006. The base rate increase includes a contribution of $27 million to Michigan's Low Income and Energy Efficiency Fund. Portions of the base rate increase are subject to refund if expenditures in certain categories are lower than assumed in establishing rates. New electric base rates became effective in mid-January 2006.
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In January 2006, an intervenor in the electric rate case filed a petition with the MPSC to seek rehearing or clarification on certain issues addressed in the December 2005 order. In January 2006, we also filed a petition to seek rehearing or clarification on certain issues in the order. We cannot predict the outcome of these petitions.
ELECTRIC TRANSMISSION EXPENSES: In December 2005, the FERC issued an order that conditionally accepts an application from METC, which provides electric transmission service to us, to increase substantially the transmission rates it will charge us in 2006. We are attempting to recover these costs through our 2006 PSCR plan case. In December 2005, the MPSC issued an order that temporarily excludes a portion of the increased costs from our PSCR charge, which began in January 2006. The PSCR process allows recovery of all reasonable and prudent power supply costs. However, we cannot predict when full recovery of these transmission costs will commence. To the extent that we incur and are unable to collect these increased costs in a timely manner, our cash flows from electric utility operations will be affected negatively. For additional details, see Note 3, Contingencies, "Electric Rate Matters -- Power Supply Costs."
ELECTRIC RESERVE MARGIN: 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 establish a reserve margin target to address various scenarios and contingencies so that the probability of interrupting service to retail customers because of a supply shortage is no greater than an industry-recognized standard. However, even with the reserve margin target, additional spot purchases may be required during periods when electric prices are high.
We are planning currently for a reserve margin of approximately 11 percent for summer 2006, or supply resources equal to 111 percent of projected firm summer peak load. Of the 2006 supply resources target of 111 percent, we expect to meet approximately 96 percent from our electric generating plants and long-term power purchase contracts, and approximately 15 percent from other contractual arrangements. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2006 through 2010. As a result, we have recognized an asset of $6 million for unexpired capacity and energy contracts at December 31, 2005.
ELECTRIC CAPACITY NEEDS FORUM: In January 2006, the MPSC Staff issued a report on future electric capacity needs in the state of Michigan. The report indicated that existing generation resources are adequate in the short term, but could be insufficient to maintain reliability standards by 2009. The report also indicated that new baseload electric generation may be needed by 2011. The MPSC Staff recommended an approval and bid process for new power plants. To address revenue stability risks, the Staff also recommended a special reliability charge a utility would assess on all electric distribution customers. In January 2006, the MPSC solicited comments on the capacity needs report and announced a public hearing for March 2006. We will continue to participate in this forum as the MPSC develops ratemaking policy to address future electric capacity needs.
INDUSTRIAL REVENUE OUTLOOK: Our electric utility customer base includes a mix of residential, commercial, and diversified industrial customers, the largest segment of which is the automotive industry. In October 2005, Delphi Corporation (Delphi) filed for Chapter 11 bankruptcy protection. Delphi is the nation's largest automotive supplier headquartered in Troy, Michigan, and is a large industrial customer of Consumers. Our electric utility operations are not dependent upon a single customer, and we do not believe that this event will have a material adverse effect on our financial condition. In November 2005, General Motors Corporation, also a large industrial customer of Consumers, announced plans to reduce manufacturing capacity, including certain operations in Michigan. We cannot predict the impact of these restructuring plans or possible future actions by other industrial customers. Continued degradation of the industrial customer base would have a negative impact on electric utility revenues.
ENERGY MARKET DEVELOPMENT: The MISO began operating the Midwest Energy Market on April 1, 2005. The Midwest Energy Market includes a day-ahead and real-time energy market and centralized generation dispatch for market participants. We are a participant in this energy market. The intention of this market is to meet load requirements in the region reliably and efficiently, to improve management of congestion on the grid, and to centralize dispatch of generation throughout the region. The MISO is now responsible for the reliability
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and economic dispatch in the entire MISO area, which covers parts of 15 states and Manitoba, including our service territory.
The settlement of charges for each operating day of the Midwest Energy Market invokes the issuance of multiple settlement statements over a 155-day period through March 2006 and a 365-day period beginning in April 2006. This extended settlement period is designed to allow for adjustments associated with the receipt of complete billing information and other adjustments. When adjustments are necessary, the MISO bills market participants on a retroactive basis, covering several months, which may result in either a positive or a negative billing adjustment. We record an expense accrual for future adjustments based on historical experience.
COAL DELIVERY DISRUPTIONS: In May 2005, western coal rail carriers experienced derailments and significant service disruptions that affected all shippers of western coal from Wyoming mines as well as coal producers from May 2005 through June 2005. Under contractual Force Majeure provisions, the coal tonnage not delivered during this period was not made up. Although we experienced some impact on coal shipments during the rail repair period, our inventories have remained within historical levels during the winter period, though at lower levels than planned before the disruptions occurred. Based on our present delivery experience, projections, and inventory, we believe we will continue to have adequate coal supply to allow for normal dispatch of our coal-fired generating units.
RENEWABLE RESOURCES PROGRAM: In January 2005, in collaboration with the MPSC, we established a RRP. Under the RRP, we purchase energy from approved renewable sources, which include solar, wind, geothermal, biomass, and hydroelectric suppliers. In August 2005, we secured long-term renewable energy supply contracts that the MPSC approved in October 2005. Customers are able to participate in the RRP in accordance with tariffs approved by the MPSC. The MPSC authorized recovery of above-market costs for the RRP by establishing a fund that consists of an annual contribution from savings generated by the RCP, a surcharge imposed by the MPSC on all customers, and contributions from customers that choose to participate in the RRP. In February 2005, the Attorney General filed appeals of the MPSC orders providing funding for the RRP in the Michigan Court of Appeals. In November 2005, the Michigan Court of Appeals issued an order that reversed the portion of the MPSC order that allows a surcharge imposed on all customers. The RRP will continue to be funded by savings generated by the RCP and by customers that participate in the program.
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 filed an appeal with the Michigan Supreme Court and, in October 2005, the Michigan Supreme Court agreed to review the lower court's decision. Consumers and other industry parties filed a brief in support of Detroit Edison's appeal. Unless overturned by the Michigan Supreme Court, the decision could encourage other municipalities to adopt similar ordinances, as has occurred or is under discussion in a few municipalities in our service territory. If incurred, we would seek recovery of these costs from our customers located in the municipality affected, 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.
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.
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 Nitrogen Oxide State Implementation Plan requires significant reductions in
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nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $815 million. The key assumptions in the capital expenditure estimate include:
- construction commodity prices, especially construction material and labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- 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 8.3 percent. As of December 2005, we had incurred $605 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $210 million of capital expenditures will be made in 2006 through 2011. These expenditures include installing selective catalytic control reduction technology at four of our coal-fired electric plants. In addition to modifying coal-fired electric plants, our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $10 million per year, which we expect to recover from our customers. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the coal-fired electric generating units emit nitrogen oxide. The expense is recovered from our customers through the PSCR process.
The EPA recently adopted a Clean Air Interstate Rule that requires additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. The rule involves a two-phase program to reduce emissions of sulfur dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule will require that we run our selective catalytic control technology units year-round beginning in 2009 and may require that we purchase additional nitrogen oxide allowances beginning in 2009.
In addition to the selective catalytic control technology installed to meet the nitrogen oxide standards, our current plan includes installation of flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to meet the Phase I reduction requirements of the Clean Air Interstate Rule, at costs similar to those to comply with the nitrogen oxide standards. We currently have a surplus of sulfur dioxide allowances, which were granted by the EPA and are accounted for as inventory. In January 2006, we sold some of our excess sulfur dioxide allowances for $61 million and recognized the proceeds as a regulatory liability.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric power plants by 2010 and further reductions by 2018. While the industry has not reached a consensus on the technical methods for curtailing mercury emissions, our capital and operating costs for mercury emissions reductions are expected to be significantly less than what was required for selective catalytic reduction technology used for nitrogen oxide compliance.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to certain aspects of EPA's Clean Air Mercury Rule, asserting that the rule is inadequate. The MDEQ has not indicated the direction that it will pursue to meet or exceed the EPA requirements through state rulemaking. We are actively participating in dialog with the MDEQ regarding potential paths for controlling mercury emissions and meeting the EPA requirements. In October 2005, the EPA announced it would reconsider certain aspects of the Clean Air Mercury Rule. We cannot predict the outcome of this proceeding.
Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases. We cannot predict whether any federal mandatory greenhouse gas emission reduction rules ultimately will be enacted, or the specific requirements of any of these rules.
To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. We cannot estimate the potential effect of federal or state level greenhouse gas policy on our future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, we
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stay abreast of and engage in 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 2007. We currently are performing the required studies to determine the most cost-effective solutions for compliance.
For additional details on electric environmental matters, see Note 3, Contingencies, "Electric Contingencies -- Electric Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of our total distribution load. It is difficult to predict future ROA customer trends.
Section 10d(4) Regulatory Assets: 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. Of the $628 million, $152 million relates to the cost of money. In June 2005, the ALJ issued a proposal for decision recommending the MPSC approve recovery of approximately $323 million in Section 10d(4) costs, which includes the cost of money through the period of collection. In December 2005, the MPSC issued an order that authorized us to recover the same costs recommended by the ALJ starting in January 2006. However, instead of collecting these costs evenly over five years, the order instructed us to collect 10 percent of the regulatory asset total in the first year, 15 percent in the second year, and 25 percent in the third, fourth, and fifth years. As a result, the total amount authorized for collection, including carrying costs, was $333 million. In January 2006, we filed a petition for rehearing with the MPSC that disputes the aspect of the order dealing with the timing of our collection of costs approved for recovery in this case. We cannot predict the outcome of this petition.
STRANDED COSTS: Prior MPSC orders adopted a mechanism pursuant to the Customer Choice Act to provide recovery of Stranded Costs that occur when customers leave our system to purchase electricity from alternative suppliers. In November 2005, we filed an application with the MPSC related to the determination of 2004 Stranded Costs. Applying the Stranded Cost methodology used in prior MPSC orders, we concluded that we experienced zero Stranded Costs in 2004.
IMPLEMENTATION COSTS: In June 2005, the MPSC issued an order that authorizes us to recover costs from the implementation of the Customer Choice Act incurred during 2002 and 2003 totaling $6 million, plus the cost of money through the period of collection. We pursued authorization at the FERC for the MISO to reimburse us for Alliance RTO development costs. Included in this amount is $2 million that the MPSC did not approve as part of our 2002 implementation costs application. The FERC denied our request for reimbursement, and we appealed the FERC ruling at the United States Court of Appeals for the District of Columbia. In November 2005, the United States Court of Appeals for the District of Columbia denied our appeal.
THROUGH AND OUT RATES: In December 2004, we began paying a transitional charge pursuant to a FERC order eliminating regional "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. Although the transitional charge ends in March 2006, there are hearings scheduled for May 2006 at the FERC to discuss these charges. The FERC hearings could result in refunds or additional transitional charges to us. We cannot predict the outcome of these hearings.
For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, "Electric Restructuring Matters," and "Electric Rate Matters."
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OTHER ELECTRIC BUSINESS UNCERTAINTIES
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. We hold a 49 percent partnership interest in the MCV Partnership, and a 35 percent lessor interest in the MCV Facility.
Under the MCV 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. Natural gas prices have increased substantially in recent years and throughout 2005. In 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and recorded an impairment charge. If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected and could result in the MCV Partnership failing to meet its obligations under the sale and leaseback transactions and other contracts. For additional details on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges. We are evaluating various alternatives in order to develop a new long-term strategy with respect to the MCV Facility.
Further, the cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity and fixed energy payments of $55 million in 2006 and $39 million in 2007. However, Consumers' direct savings from the RCP, after allocating a portion to customers, are used to offset our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse effect on the MCV Partnership's financial performance, 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 15, 2007. We believe that the clause is valid and fully effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out clause, the MCV Partnership may have the right to terminate the MCV PPA. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 15, 2007 may affect negatively the financial performance of the MCV Partnership.
For additional details on the MCV Partnership, see Note 3, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
NUCLEAR MATTERS:
Big Rock: Decommissioning of the site is nearing completion. Demolition of the last remaining plant structure, the containment building, and removal of remaining underground utilities and temporary office structures is expected to be completed by the summer of 2006. Final radiological surveys will then be completed including confirmatory surveys performed by the NRC to ensure that the site meets all requirements for free, unrestricted release in accordance with the NRC approved License Termination Plan (LTP) for the project. We anticipate NRC approval to return approximately 485 acres of the site, including the area formerly occupied by the nuclear plant, to a natural setting for unrestricted use by early 2007. We expect another area of approximately 105 acres encompassing the Big Rock Independent Spent Fuel Storage Installation (ISFSI), where eight casks loaded with spent fuel and other high-level radioactive material are stored, to be returned to a natural state within approximately two years from the date the DOE finishes removing the spent fuel from Big Rock also in accordance with the LTP.
Palisades: In August 2005, the NRC completed its performance review of the Palisades Nuclear Plant for the first half of the calendar year 2005. The NRC determined that Palisades was operated in a manner that preserved public health and safety and met all of the NRC's specific "cornerstone objectives." As of August 2005, all inspection findings were classified as having very low safety significance and all performance
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indicators show performance at a level requiring no additional oversight. Based on the plant's performance, only regularly scheduled inspections are planned through March 31, 2007.
The amount of spent nuclear fuel at Palisades exceeds the plant's temporary onsite wet storage pool capacity. We are using dry casks for temporary onsite dry storage to supplement the wet storage pool capacity. As of January 2006, we have loaded 29 dry casks with spent nuclear fuel.
Palisades' current license from the NRC expires in 2011. In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. Certain parties are seeking to intervene and have requested a hearing on the application. The NRC has stated that it expects to take 22-30 months to review a license renewal application. We expect a decision from the NRC in 2007.
Palisades, like other nuclear plants, has experienced cracking in reactor head nozzle penetrations. Repairs to two nozzles were made in 2004. We have authorized the purchase of a replacement reactor vessel closure head. The replacement head is being manufactured and is scheduled to be installed in 2007.
In December 2005, we announced plans to sell the Palisades nuclear plant and enter into a long-term power purchase agreement with the new owner. We believe a sale is the best option for our company, as it will reduce risk and improve cash flow while retaining the benefits of the plant for customers.
The Palisades sale will use a competitive bid process, providing interested companies the option to bid on the plant, as well as the related decommissioning liabilities and trust funds assets, and spent nuclear fuel at Palisades and Big Rock. We expect to complete the sale in 2007.
For additional details on nuclear plant decommissioning at Big Rock and Palisades, see Note 3, Contingencies, "Other Electric Contingencies -- Nuclear Plant Decommissioning."
GAS BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to be relatively flat. Actual gas deliveries in future periods may be affected by:
- fluctuations in weather patterns,
- use by independent power producers,
- competition in sales and delivery,
- changes in gas commodity prices,
- Michigan economic conditions,
- the price of competing energy sources or fuels, and
- gas consumption per customer.
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 2005-2006. We started construction of Phase I of the pipeline in June 2005. Phase I of the project was completed and put in service in early December 2005. We anticipate completion of Phase II of the project in 2008.
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. In August 2005, the MPSC issued an order approving the application. Construction of the pipeline is expected to begin in mid-2006.
GAS BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our future financial results and financial condition. These trends or uncertainties could have a material impact on revenues or income from gas operations.
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GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 3, Contingencies, "Gas Contingencies -- Gas Environmental Matters."
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs for prudency in an annual reconciliation proceeding. For additional details on gas cost recovery, see Note 3, Contingencies, "Gas Rate Matters -- Gas Cost Recovery."
2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously ordered $34 million reduction in our depreciation expense,
- required us to undertake a study to determine why our plant removal costs are in excess of other regulated Michigan natural gas utilities, and
- required us to file a study report with the MPSC Staff on or before December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.
We are also required to file our next gas depreciation case within 90 days after the MPSC issuance of a final order in the pending case related to ARO accounting. We expect an MPSC order in the first quarter of 2006.
If the depreciation case order is issued after the gas general rate case order, we proposed to incorporate its results into the gas general rates using a surcharge mechanism.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking a 12 percent authorized return on equity along with a $132 million annual increase in our gas delivery and transportation rates. The primary reasons for the request are recovery of new investments, carrying costs on natural gas inventory related to higher gas prices, system maintenance, employee benefits, and low-income assistance. If approved, the request would add approximately 5 percent to the typical residential customer's average monthly bill. The increase would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million. The MPSC Staff and intervenors filed interim rate relief testimony on October 31, 2005. In its testimony, the MPSC Staff recommended granting interim rate relief of $38 million. As of February 2006, the MPSC has not acted on our interim rate relief request.
On February 13, 2006, the MPSC Staff recommended granting final rate relief of $62 million. The MPSC Staff proposed that $17 million of this amount be contributed to a low income energy efficiency fund. The MPSC Staff also recommended reducing our return on common equity to 11.15 percent, from our current 11.4 percent.
EMERGENCY RULES REGARDING BILLING PRACTICES: On October 18, 2005, the MPSC issued an order adopting emergency rules for the winter heating period of November 1, 2005 through March 31, 2006. The rules address billing practices for retail customers of electric and gas utilities subject to the MPSC's jurisdiction. The emergency rules are designed to address the increase in heating costs this winter. They address billing cycles, fees, deposits, shutoffs, and collection of unpaid bills. The emergency rules will have an estimated $4 million negative effect on our collections and cash flow in 2006.
OTHER OUTLOOK
MCV IMPAIRMENT ISSUES: Due to the impairment of the MCV Facility, the equity held by the minority interest owners of the MCV Partnership has decreased significantly. Since we have the controlling financial interest in the MCV Partnership, we will record 100 percent of future losses incurred at the MCV Partnership, not just our proportionate share.
The impairment of the MCV Facility, and any potential future impairment of the MCV Facility, will likely decrease the amount of equity investment recognized for ratemaking in future electric and gas rate orders. Lower equity investment may result in a reduced revenue requirement. However, we cannot predict the outcome of any future rate cases, which may be lower or higher based on several factors, including the amount of equity CE-30
investment and related risk. For additional information on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges.
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 a class action lawsuit alleging ERISA violations. For additional details regarding this investigation and litigation, see Note 3, Contingencies.
PENSION REFORM: Both branches of Congress passed legislation aimed at reforming pension plans. The U.S. Senate passed The Pension Security and Transparency Act in November 2005 and The House of Representatives passed the Pension Protection Act of 2005 in December 2005. At the core of both bills are changes in the calculation of pension plan funding requirements effective for plan years beginning in 2007, with interest rate relief extended until then, and an increase in premiums paid to the Pension Benefit Guaranty Corporation (PBGC). The latter was addressed through the broader budget reconciliation bill, which raises the PBGC flat-rate premiums from $19 to $30 per participant per year beginning in 2006. Although the Senate and House bills are similar, they do contain a number of technical differences, including differences in the time period allowed for interest rate and asset smoothing, the interest rate used to calculate lump sum payments, and the criteria used to determine whether a plan is "at-risk," which requires higher contribution levels. The Senate and the House plan to work out the differences between the two bills in a joint conference. The timing, however, of a final pension reform bill is unknown. We are analyzing the impact of this legislation.
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS: This Interpretation became effective for us on December 31, 2005. It clarifies the term "conditional asset retirement obligation" as used in SFAS No. 143 and specifies that an obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Upon adoption of this Interpretation, we recorded $36 million of conditional asset retirement obligations relating to asbestos abatement. Implementation did not impact results of operations due to regulatory accounting. For additional details, see Note 7, Asset Retirement Obligations.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. Companies must expense this amount over the vesting period of the awards. This 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 including the timing of expense recognition for share-based awards with terms that accelerate vesting upon retirement. As a result of these clarifications, future compensation costs for share-based awards with accelerated vesting provisions upon retirement will need to be fully expensed by the period in which the employee becomes eligible to retire. At December 31, 2005, unrecognized compensation cost for such share-based awards held by retirement eligible employees was not material.
SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. The modified prospective method applies the recognition provisions to all awards granted or modified after the adoption date of this Statement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective. For details regarding current accounting for share-based awards, see Note 9, Executive Incentive Compensation.
The SEC issued SAB No. 107 to express the views of the Staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. Also, the SEC issued SAB No. 107 to provide the Staff's views regarding the valuation of share-based payments, including assumptions such as expected volatility and expected term. We applied the additional guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R). CE-31
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CONSUMERS ENERGY COMPANY CONSOLIDATED STATEMENTS OF INCOME (LOSS)
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-35
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
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The accompanying notes are an integral part of these statements. CE-37
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-39
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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 serving 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 and operate principally in two business segments: electric utility and gas utility.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include Consumers, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with Revised FASB Interpretation No. 46. We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. We eliminate intercompany transactions and balances.
USE OF ESTIMATES: We prepare our consolidated financial statements in conformity with U.S. 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 3, Contingencies.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity and natural gas, and the storage of natural gas when services are provided. Sales taxes are recorded as liabilities and are not included in revenues.
ACCOUNTING FOR MISO TRANSACTIONS: We account for MISO transactions on a net basis for all of our generating units combined. We record billing adjustments when invoices are received and an expense accrual for future adjustments based on historical experience.
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, RESTRICTED CASH AND RESTRICTED SHORT-TERM INVESTMENTS: All highly liquid investments with an original maturity of three months or less are considered cash equivalents.
At December 31, 2005, our restricted cash and restricted short-term investments on hand was $183 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. Restricted short-term investments consist of $128 million of U.S. Treasury securities deposited with a trustee for the purpose of extinguishing the current portion of long-term debt -- related parties. These investments have original maturity dates of less than one year and, because of their short-term maturities, carrying amounts approximate fair value.
COLLECTIVE BARGAINING AGREEMENTS: At December 31, 2005, approximately 45 percent of our employees were represented by the Utility Workers of America Union. The Union represents Consumers' operating, maintenance, and construction employees and our call center employees.
FINANCIAL AND DERIVATIVE 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.
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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.
We account for derivative instruments using SFAS No. 133. Derivatives are reported on the balance sheet at their fair value. Changes in fair value are recorded to accumulated other comprehensive income if the derivative qualifies for cash flow hedge accounting; otherwise, the changes are recorded to earnings.
For additional details regarding financial and derivative instruments, see Note 5, Financial and Derivative Instruments.
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, also included in this category, is stated at the lower of cost or market and valued using the last-in, first-out (LIFO) method. The amount of reserve to reduce the MCV Partnership's inventory from the first-in, first-out (FIFO) basis to the LIFO basis was $15 million at December 31, 2005 and $10 million at December 31, 2004. Inventory cost determined on a FIFO basis approximates current replacement cost.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate the potential impairment of our investments and other long-lived assets, other than goodwill, based on various analyses, including the projection of undiscounted cash flows, whenever events or changes in circumstances indicate that the carrying amount of the investment or asset may not be recoverable. If the carrying amount of the investment or asset exceeds its estimated undiscounted future cash flows, an impairment loss is recognized and the investment or asset is written down to its estimated fair value. For additional details, see Note 2, Asset Impairment Charges.
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. Our DOE liability is $145 million at December 31, 2005 and $141 million at December 31, 2004. This amount includes 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 Electric Contingencies -- Nuclear Matters."
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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, along with associated cost of removal net of salvage. Cost of removal collected from our customers, but not spent, is recorded as a regulatory liability. 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. For additional details, see Note 7, Asset Retirement Obligations and Note 11, Property, Plant, and Equipment.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for comparative purposes. These reclassifications did not affect consolidated net income for the years presented.
RELATED PARTY TRANSACTIONS: We received income from related parties as follows:
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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 14, Consolidation of Variable Interest Entities.
(b) We issued Trust Preferred Securities through several Consumers' affiliated companies. At December 31, 2003, we deconsolidated the trusts that hold the mandatorily redeemable Trust Preferred Securities. As a result, we now record on the Consolidated Statements of Income, Interest on Long-term debt -- related parties to the trusts holding the Trust Preferred Securities.
(c) We base our related party transactions on regulated prices, market prices, or competitive bidding. We pay overhead costs to CMS Energy based on an industry allocation methodology, such as the Massachusetts Formula.
(d) Panhandle was sold in June 2003.
We own 2.3 million shares of CMS Energy Common Stock with a fair value of $33 million at December 31, 2005. For additional details on our investment in CMS Energy Common Stock, see Note 5, 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 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 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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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 seven years.
- ------------------------- (a) At December 31, 2005, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.781 billion of regulatory assets as non-current regulatory assets. At December 31, 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, 2005 and December 31, 2004, all of our regulatory liabilities represented non-current regulatory liabilities.
2: ASSET IMPAIRMENT CHARGES
The MCV Partnership's costs of producing electricity are tied to the price of natural gas, but its revenues do not vary with changes in the price of natural gas. In 2005, NYMEX forward natural gas price forecasts for the years 2005 through 2010 increased substantially. Additionally, other independent natural gas long-term forward price forecasting organizations indicated their intention to raise their forecasts for the price of natural gas generally over the entire long-term forecast horizon beyond 2010. Our analysis and assessment of this information suggested that forward natural gas prices for the period from 2006 through 2010 could average approximately $9 per mcf. Further, this information indicated that natural gas prices could average approximately $6.50 per mcf over the long term beyond 2010. As a result, in 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and determined that an impairment analysis, considering revised forward natural gas price assumptions, was required. In its impairment analysis, the MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows at a 4.3 percent risk free interest rate. The carrying value of the MCV Partnership's fixed assets exceeded the estimated fair value resulting in an impairment charge of $1.159 billion to recognize the reduction in fair value of the MCV Facility's fixed assets. As a result, our 2005 net income was reduced by $369 million after accounting for minority interests and tax effects. After reflecting the impairment charge, the MCV Partnership's fixed assets, which are included on our Consolidated Balance Sheets, are valued at $224 million at December 31, 2005.
If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected, which could result in the MCV Partnership failing to meet its obligations under the sale and
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leaseback transactions, and other contracts and could result in an impairment of the FMLP. At December 31, 2005, our investment in the FMLP was $235 million.
Our 49 percent interest in the MCV Partnership is held through our wholly-owned subsidiary, CMS Midland. The severe adverse change in the anticipated economics of the MCV Partnership operations discussed within this Note also led to our decision to impair certain assets carried on the balance sheet of CMS Midland. These assets represented interest capitalized during the construction of the MCV Facility, which were being amortized over the life of the MCV Facility. In the third quarter of 2005, we recorded an impairment charge of $25 million ($16 million, net of tax) to reduce the carrying amount of these assets to zero.
The total of the CMS Midland impairment and the MCV Partnership impairment discussed above is $1.184 billion, before tax, and $385 million net of taxes and minority interest.
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, 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 nor denied the order's findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading by CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals, in accordance with existing indemnification policies.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of complaints were filed against CMS Energy, Consumers, and certain officers and directors of CMS Energy and its affiliates, including but not limited to Consumers which, while established, operated and regulated as a separate legal entity and publicly traded company, shares a parallel Board of Directors with CMS Energy. 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 running from May 2000 through March 2003. The cases were consolidated into a single lawsuit. The consolidated lawsuit generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy's business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, a motion was granted, dismissing Consumers and three of the individual defendants, but the court denied the motions to dismiss for CMS Energy and the 13 remaining individual defendants. Plaintiffs filed a motion for class certification on April 15, 2005 and an amended motion for class certification on June 20, 2005. The hearing on this motion is scheduled for February 28, 2006. On September 20, 2005, CMS Energy filed a motion for judgment on the pleadings, based on the Dura Pharmaceuticals decision issued by the United States Supreme Court. Plaintiffs filed their response on October 25, 2005, along with a so-called "cross- CE-46
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motion for partial summary judgment" seeking a determination that CMS Energy is liable for all damages proximately caused by its "culpable conduct." On November 29, 2005, the judge issued a decision denying both CMS Energy's motion for judgment on the pleadings and plaintiffs' cross-motion for partial summary judgment. CMS Energy and the individual defendants will defend themselves vigorously in this litigation but cannot predict its outcome.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST, and certain named and unnamed officers and directors, in two lawsuits brought as purported class actions on behalf of participants and beneficiaries of the CMS Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July 2002 in United States District Court for the Eastern District of Michigan, were consolidated by the trial judge and an amended consolidated complaint was filed. Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution on behalf of the Plan with respect to a decline in value of the shares of CMS Energy Common Stock held in the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge has conditionally granted plaintiffs' motion for class certification. A trial date has not been set, but is expected to be no earlier than mid-2006 in the absence of an intervening settlement of the lawsuits. Settlement negotiations among counsel for the parties and CMS Energy's fiduciary insurance carrier are ongoing. In the absence of such a settlement, CMS Energy and Consumers will defend themselves vigorously in this litigation but cannot predict its outcome.
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: Compliance with the federal Clean Air Act and resulting regulations has been, and will continue to be, a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $815 million. The key assumptions in the capital expenditure estimate include:
- construction commodity prices, especially construction material and labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- 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 8.3 percent. As of December 2005, we had incurred $605 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $210 million of capital expenditures will be made in 2006 through 2011. These expenditures include installing selective catalytic control reduction technology at four of our coal-fired electric plants. In addition to modifying coal-fired electric plants, our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $10 million per year, which we expect to recover from our customers. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the coal-fired electric generating units emit nitrogen oxide. The expense is recovered from our customers through the PSCR process.
The EPA recently adopted a Clean Air Interstate Rule that requires additional coal-fired electric plant emission controls for nitrogen oxides and sulfur dioxide. The rule involves a two-phase program to reduce emissions of sulfur dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule will require CE-47
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that we run our selective catalytic control technology units year round beginning in 2009 and may require that we purchase additional nitrogen oxide allowances beginning in 2009.
In addition to the selective catalytic control technology installed to meet the nitrogen oxide standards, our current plan includes installation of flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to meet the Phase I reduction requirements of the Clean Air Interstate Rule, at costs similar to those to comply with the nitrogen oxide standards. We currently have a surplus of sulfur dioxide allowances, which were granted by the EPA and are accounted for as inventory. In January 2006, we sold some of our excess sulfur dioxide allowances for $61 million and recognized the proceeds as a regulatory liability.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric power plants by 2010 and further reductions by 2018. While the industry has not reached a consensus on the technical methods for curtailing mercury emissions, our capital and operating costs for mercury emissions reductions are expected to be significantly less than what was required for selective catalytic reduction technology used for nitrogen oxide compliance.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to certain aspects of EPA's Clean Air Mercury Rule, asserting that the rule is inadequate. The MDEQ has not indicated the direction that it will pursue to meet or exceed the EPA requirements through state rulemaking. We are actively participating in dialog with the MDEQ regarding potential paths for controlling mercury emissions and meeting the EPA requirements. In October 2005, the EPA announced it would reconsider certain aspects of the Clean Air Mercury Rule. We cannot predict the outcome of this proceeding.
The EPA has alleged that some utilities have incorrectly classified plant modifications as "routine maintenance" rather than seeking 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.
Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental Protection Act, we expect that we will ultimately incur investigation and remedial action costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies.
We are a potentially responsible party at several contaminated sites administered under Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties with substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for the known Superfund sites will be between $2 million and $10 million. At December 31, 2005, 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 Ludington. 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.
MCV Environmental Issue: On July 12, 2004, the MDEQ, Air Control Division, issued the MCV Partnership a Letter of Violation asserting that the MCV Facility violated its Air Use Permit to Install (PTI) by exceeding the carbon monoxide emission limit on the Unit 14 duct burner and failing to maintain certain records in the required format. The MCV Partnership has declared five of the six duct burners in the MCV Facility as unavailable for operational use (which reduces the generation capability of the MCV Facility by approximately 100 MW) and took other corrective action to address the MDEQ's assertions. The one available duct burner was tested in April 2005 and its emissions met permitted levels due to the configuration of that particular unit. The MCV Partnership disagrees with certain of the MDEQ's assertions. The MCV Partnership filed a response in July 2004 to address the Letter of Violation. On December 13, 2004, the MDEQ informed the MCV Partnership
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that it was pursuing an escalated enforcement action against the MCV Partnership regarding the alleged violations of the MCV Facility's PTI. The MDEQ also stated that the alleged violations are deemed federally significant and, as such, placed the MCV Partnership on the EPA's High Priority Violators List (HPVL). The MDEQ and the MCV Partnership are pursuing voluntary settlement of this matter, which will satisfy state and federal requirements and remove the MCV Partnership from the HPVL. Any such settlement may involve a fine, but at this time, the MDEQ has not stated what, if any, fine they will seek to impose. At this time, the MCV Partnership management cannot predict the financial impact or outcome of this issue.
On July 13, 2004, the MDEQ, Water Division, issued the MCV Facility a Notice Letter asserting the MCV Facility violated its National Pollutant Discharge Elimination System (NPDES) Permit by discharging heated process wastewater into the storm water system, failing to document inspections, and other minor infractions (alleged NPDES violations). In August 2004, the MCV Partnership filed a response to the MDEQ letter covering the remediation for each of the MDEQ's alleged violations. On October 17, 2005, the MDEQ, Water Bureau, issued the MCV Partnership a Compliance Inspection report, which listed several minor violations and concerns that needed to be addressed by the MCV Facility. This report was issued in connection with an inspection of the MCV Facility in September 2005, which was conducted for compliance and review of the Storm Water Pollution Prevention Plans (SWPPP). The MCV Partnership submitted its updated SWPPP on December 1, 2005. The MCV Partnership management believes it has resolved all issues associated with the Notice Letter and Compliance Inspection and does not expect any further MDEQ actions on these matters.
ALLOCATION OF BILLING COSTS: In February 2006, the MPSC issued an order, which determined that we violated the MPSC code of conduct by including a bill insert advertising an unregulated service. The MPSC issued a penalty of $45,000 and stated that any subsidy for the use of our billing system arising from past code of conduct violations will be accounted for in our next electric rate case. We cannot predict the outcome or the impact on any future electric rate case.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. 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 plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The plaintiffs also filed suit in the United States Court for the Western District of Michigan, which the judge subsequently dismissed. The plaintiffs have appealed the dismissal to the United States Court of Appeals. We cannot predict the outcome of these appeals.
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC ROA: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2005, alternative electric suppliers were providing 552 MW of generation service to ROA customers. This amount represents a decrease of 40 percent compared to December 31, 2004, and is 7 percent of our total distribution load. It is difficult to predict future ROA customer trends.
STRANDED COSTS: Prior MPSC orders adopted a mechanism pursuant to the Customer Choice Act to provide recovery of Stranded Costs that occur when customers leave our system to purchase electricity from alternative suppliers. In November 2005, we filed an application with the MPSC related to the determination of 2004 Stranded Costs. Applying the Stranded Cost methodology used in prior MPSC orders, we concluded that we experienced zero Stranded Costs in 2004.
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ELECTRIC RATE MATTERS
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 covering partially the estimated reserve margin requirements for 2006 through 2010. As a result, we have recognized an asset of $6 million for unexpired capacity and energy contracts at December 31, 2005. The total premium costs of electric capacity and energy contracts for 2005 were approximately $8 million.
PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. Revenues from the PSCR charges are subject to reconciliation after actual costs are reviewed for reasonableness and prudence. In March 2005, we submitted our 2004 PSCR reconciliation filing to the MPSC.
In September 2005, we submitted our 2006 PSCR plan filing to the MPSC. In November 2005, we submitted an amended 2006 PSCR plan to the MPSC to include higher estimates for certain transmission and coal supply costs. In December 2005, the MPSC issued an order that temporarily excludes a portion of the increased costs from our PSCR charge. The order also includes a one mill per kWh reduction in the PSCR charge. We implemented this PSCR charge in January 2006. If the temporary order remains in effect for the remainder of 2006, it would result in a delay in the recovery of $87 million related to these excluded power supply costs. We expect to recover fully these costs through the PSCR process. To the extent that we incur and are unable to collect these costs in a timely manner, our cash flows from electric utility operations will be affected negatively. We are seeking full recovery of filed 2006 costs in 2006 as part of this proceeding. 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. 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 14, Consolidation of Variable Interest Entities.
Under the MCV 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. Natural gas prices have increased substantially in recent years and throughout 2005. In 2005, the MCV Partnership reevaluated the economics of operating the MCV Facility and recorded an impairment charge. If natural gas prices remain at present levels or increase, the operations of the MCV Facility would be adversely affected and could result in the MCV Partnership failing to meet its obligations under the sale and leaseback transactions and other contracts. For additional details on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges. We are evaluating various alternatives in order to develop a new long-term strategy with respect to the MCV Facility.
Further, the cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. Underrecoveries of capacity and fixed energy payments totaled $59 million in 2005, and were expensed directly to income. We estimate underrecoveries of $55 million in 2006 and $39 million in 2007. However, Consumers' direct savings from the RCP, after allocating a portion to customers, are used to offset our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. The MCV Partnership has indicated that it may take issue with our exercise of the regulatory out clause after September 15, 2007. We believe that the clause is valid and fully
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effective, but cannot assure that it will prevail in the event of a dispute. If we are successful in exercising the regulatory out clause, the MCV Partnership may have the right to terminate the MCV PPA. The MPSC's future actions on the capacity and fixed energy payments recoverable from customers subsequent to September 15, 2007 may affect negatively the financial performance of the MCV Partnership.
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 reduces the MCV Facility's annual production of electricity and, as a result, reduces 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 MCV Facility fuel cost savings are first used to offset fully the cost of replacement power. Second, $5 million annually, funded jointly by Consumers and the MCV Partnership, is contributed to our RRP. Remaining savings are split between the MCV Partnership and Consumers. Consumers shared 50 percent of its direct savings in 2005, and will share 70 percent of its direct savings in 2006 and beyond. 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, we implemented the RCP. The underlying agreement for the RCP between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In February 2005, a group of intervenors in the RCP case filed for rehearing of the MPSC order approving the RCP. The Attorney General also filed an appeal with the Michigan Court of Appeals. We cannot predict the outcome of these matters.
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 City of Midland appealed the decision to the Michigan Court of Appeals, and the MCV Partnership 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 2005. The MCV Partnership estimates that the 1997 through 2005 tax year cases will result in a refund to the MCV Partnership of approximately $83 million, inclusive of interest, if the decision of the Michigan Tax Tribunal is upheld. In February 2006, the Michigan Court of Appeals primarily affirmed the Michigan Tax Tribunal decision, but remanded the case back to the Michigan Tax Tribunal to clarify certain aspects of the Tax Tribunal decision. The remanded proceedings may result in the determination of a greater refund to the MCV Partnership. The MCV Partnership cannot predict the outcome of these proceedings; therefore, this anticipated refund has not been recognized in 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 decommissioning, this estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. Recently updated cost projections for Big Rock indicate an anticipated decommissioning cost of $395 million as of the end of 2005.
Big Rock: In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. Excluding the additional nuclear fuel storage costs due to the DOE's failure to accept 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 $57 million. At this time, we plan to provide the additional amounts needed from our corporate funds and, subsequent to the completion in 2007 of radiological decommissioning work, seek recovery of such expenditures from some
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alternative source. We cannot assume that such efforts will be successful. 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, 2005, we have an investment in nuclear decommissioning trust funds of $10 million for Big Rock. In addition, at December 31, 2005, we have charged $9 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.
Palisades: Excluding additional nuclear fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we concluded, based on the costs estimates filed in March 2004, that the existing surcharge for Palisades needed to be increased to $25 million annually, beginning January 1, 2006, and continuing 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 January 2005, we filed a settlement agreement with the MPSC that was agreed to by four of the six parties involved in the proceeding. 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. In September 2005, the MPSC approved the contested settlement. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability.
At December 31, 2005, we have an investment in the MPSC nuclear decommissioning trust funds of $534 million for Palisades. In addition, at December 31, 2005, we have a FERC decommissioning trust fund with a balance of $11 million. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 7, Asset Retirement Obligations.
In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. Certain parties are seeking to intervene and have requested a hearing on the application. The NRC has stated that it expects to take 22-30 months to review a license renewal application. We expect a decision from the NRC in 2007. At this time, we cannot determine what impact this will have on decommissioning costs or the adequacy of funding.
In December 2005, we announced plans to sell Palisades and have begun pursuing this asset divestiture. As a sale is not probable to occur until a firm purchase commitment is entered into with a potential buyer, we have not classified the Palisades assets as held for sale on our Consolidated Balance Sheets.
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. On April 29, 2005, the court ruled on various motions for summary judgment filed by the DOE and us. The court denied the DOE's motions to dismiss portions of the complaint including its motion seeking recovery of a one-time fee payable by us prior to delivery of the spent nuclear fuel. The court granted the DOE's motion to recoup this fee against any
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damages awarded to us. The court granted our motion for summary judgment on liability. If our litigation against the DOE is successful, we plan to use any 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, in due course, will submit a final license application to the NRC for the repository. The application and review process is estimated to take several years.
Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $28 million in any policy year if insured losses in excess of NEIL's maximum policyholders surplus occur at our, or any other member's, nuclear facility. NEIL's policies include coverage for acts of terrorism.
At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear energy hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. 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 $15 million.
We also maintain insurance under a program that covers tort claims for bodily injury to nuclear workers caused by nuclear hazards. The policy contains a $300 million nuclear industry aggregate limit. Under a previous insurance program providing coverage for claims brought by nuclear workers, we remain responsible for a maximum assessment of up to $6 million. This requirement will end December 31, 2007.
Big Rock remains insured for nuclear liability 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 remediation costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through insurance proceeds and MPSC-approved rates. At December 31, 2005, we have a liability of $29 million, net of $53 million of expenditures incurred to date, and a regulatory asset of $62 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.
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
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orders only apply to a title transfer tracking fee charged and collected in connection with 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 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.
We have one GCR reconciliation filing pending with the MPSC for the 2004-2005 GCR year. It was filed in June 2005. We have calculated a $2 million net overrecovery for the GCR year, including interest through March 2005 and refunds that we received from our suppliers that are required to be refunded to our customers. The case schedule has been suspended to allow for settlement discussions.
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 proposed 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 purchased natural gas 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.
In June 2005, four of the five parties filed a settlement agreement. The fifth party filed a statement of non-objection. The settlement agreement includes a GCR ceiling price adjustment contingent upon future events.
In September 2005, we filed a motion with the MPSC seeking to reopen our GCR plan for year 2005-2006. Since the settlement agreement entered into in June 2005, there have been unanticipated increases in the market price for natural gas.
In November 2005, the MPSC issued an Order related to our reopened GCR plan for year 2005-2006. The order approved the June 2005 settlement agreement along with a new GCR factor consisting of a fixed cap of $10.10 per mcf for the December 2005 through March 2006 billing period. Our GCR factor for the billing month of February 2006 is $8.20 per mcf. One of the intervenors in this case has appealed the MPSC Order to the Michigan Court of Appeals. We are unable to predict the outcome of this appeal.
GCR plan for year 2006-2007: In December 2005, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2006 through March 2007. Our request proposed using a GCR factor consisting of:
- a base GCR factor of $11.10 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future events.
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2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously ordered $34 million reduction in our depreciation expense,
- required us to undertake a study to determine why our plant removal costs are in excess of other regulated Michigan natural gas utilities, and
- required us to file a study report with the MPSC Staff on or before December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.
We are also required to file our next gas depreciation case within 90 days after the MPSC issuance of a final order in the pending case related to ARO accounting. We expect an MPSC order in the first quarter of 2006.
If the depreciation case order is issued after the gas general rate case order, we proposed to incorporate its results into the gas general rates using a surcharge mechanism.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking a 12 percent authorized return on equity along with a $132 million annual increase in our gas delivery and transportation rates. The primary reasons for the request are recovery of new investments, carrying costs on natural gas inventory related to higher gas prices, system maintenance, employee benefits, and low-income assistance. If approved, the request would add approximately 5 percent to the typical residential customer's average monthly bill. The increase would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million. The MPSC Staff and intervenors filed interim rate relief testimony on October 31, 2005. In its testimony, the MPSC Staff recommended granting interim rate relief of $38 million. As of February 2006, the MPSC has not acted on our interim rate relief request.
On February 13, 2006, the MPSC Staff recommended granting final rate relief of $62 million. The MPSC Staff proposed that $17 million of this amount be contributed to a low income energy efficiency fund. The MPSC Staff also recommended reducing our return on common equity to 11.15 percent, from our current 11.4 percent.
OTHER CONTINGENCIES
IRS RULING: In August 2005, the IRS issued Revenue Ruling 2005-53 and regulations to provide guidance with respect to the use of the "simplified service cost" method of tax accounting. We use this tax accounting method, generally allowed by the IRS under section 263A of the Internal Revenue Code, with respect to the allocation of certain corporate overheads to the tax basis of self-constructed utility assets. Under the IRS guidance, significant issues with respect to the application of this method remain unresolved and subject to dispute. However, the effect of the IRS's position may be to require Consumers either (1) to repay a portion of previously received tax benefits, or (2) to add back to taxable income, half in each of 2005 and 2006, a significant portion of previously deducted overheads. The impact of this matter on future earnings, cash flows, or our present NOL carryforwards remains uncertain, but could be material. We have recorded an increase in our taxable income of $359 million in 2005, and a corresponding reduction in deferred taxes related to property, to reflect the estimated 2005 effect of the new regulation. For additional information, see Note 8, Income Taxes. Consumers cannot predict the outcome of this matter.
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.
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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.
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: The Interpretation requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee. The initial recognition and measurement provision of this Interpretation does not apply to some guarantee contracts, such as product warranties, derivatives, or guarantees between corporations under common control, although disclosure of these guarantees is required.
The following table describes our guarantees at December 31, 2005:
The following table provides additional information regarding our guarantees:
At December 31, 2005, none of our guarantees contained provisions allowing us to recover, from third parties, any amount paid under the guarantees. In the ordinary course of business, we enter into agreements containing indemnifications in connection with a variety of transactions including financing agreements. While we cannot estimate our maximum exposure under these indemnities, we consider the probability of liability remote.
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4: FINANCINGS AND CAPITALIZATION
Long-term debt at December 31 follows:
- ------------------------- (a) Represents the weighted average interest rate at December 31, 2005 (5.188 percent at December 31, 2004).
(b) We consolidate the FMLP in accordance with Revised FASB Interpretation No. 46. The FMLP debt is 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 2005:
Costs associated with 2005 debt issuances totaled $13 million and are being amortized over the lives of the related debt. Call premiums associated with the 2005 debt retirements totaled $10 million and are being amortized over the lives of the newly issued debt.
FIRST MORTGAGE BONDS: We secure our FMB 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. See "FMB Indenture Limitations" section within this Note.
SECURITIZATION BONDS: Certain regulatory assets collateralize Securitization bonds. We are not the owners of these 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 collected are remitted to a trustee for the Securitization bonds and are not available to our creditors. Securitization surcharges totaled $50 million annually in 2005 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 in the following table. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trusts issued. We determined that we do not hold the controlling financial interest in our trust preferred security structures. Accordingly, those entities are reflected in Long-term debt -- related parties.
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The following is a summary of Long-term debt -- related parties at December 31:
- ------------------------- (a) Extinguished in February 2006.
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, 2005, the aggregate annual maturities for long-term debt and long-term debt -- related parties for the next five years are:
REGULATORY AUTHORIZATION FOR FINANCINGS: In April 2005, the FERC issued an authorization to permit us to issue up to an additional $1.0 billion ($2.0 billion in total) of long-term securities for refinancing or refunding purposes, and up to an additional $1.0 billion ($2.5 billion in total) of long-term securities for general corporate purposes during the period ending June 30, 2006.
Combined with remaining availability from previously issued FERC authorizations, we can now issue up to:
- $876 million of long-term securities for refinancing or refunding purposes,
- $1.159 billion of long-term securities for general corporate purposes, and
- $1.935 billion of long-term FMB to be issued solely as collateral for other long-term securities.
FMB INDENTURE LIMITATIONS: Irrespective of our existing FERC authorization, our ability to issue FMB as primary obligations or as collateral for financing is governed by certain provisions of our indenture dated September 1, 1945 and its subsequent supplements. Due to the adverse impact of the MCV Partnership asset impairment charge recorded in September 2005 on the net earnings coverage test in one of the governing bond-issuance provisions of the indenture, we expect our ability to issue additional FMB will be limited to $298 million through September 30, 2006. After September 30, 2006, our ability to issue FMB in excess of $298 million will be based on achieving a two-times FMB interest coverage ratio.
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REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities with banks are available at December 31, 2005:
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at December 31, 2005, we had $179 million of unrestricted retained earnings available to pay common stock dividends. Covenants in our debt facilities cap common stock dividend payments at $300 million in a calendar year. During 2005, we paid $277 million in common stock dividends to CMS Energy.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales program, we currently sell certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. The special purpose entity sold $325 million of receivables at December 31, 2005 and $304 million of receivables at December 31, 2004. We continue to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against our other assets for failure of a debtor to pay when due and no right to any receivables not sold. We have neither recorded a gain or loss on the receivables sold nor retained interest in the receivables sold.
Certain cash flows under our accounts receivable sales program are shown in the following table:
PREFERRED STOCK: Our Preferred Stock outstanding follows:
5: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments or other valuation techniques.
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The cost and fair value of our long-term financial instruments are as follows:
- ------------------------- (a) Includes current maturities of $85 million at December 31, 2005 and $118 million at December 31, 2004. Settlement of long-term debt is generally not expected until maturity.
(b) Includes current maturities of $129 million at December 31, 2005 and $180 million at December 31, 2004.
(c) At December 31, 2005, we held 2.3 million shares of CMS Energy Common Stock.
(d) Nuclear decommissioning investments include cash and cash equivalents and accrued income totaling $12 million at December 31, 2005 and $11 million at December 31, 2004. 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 at December 31, 2005 is as follows:
Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $91 million at December 31, 2005 and $139 million at 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-term maturities, carrying amounts approximate fair value.
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not limited to, changes in commodity prices, interest rates, and equity security prices. We may use various contracts to manage these risks, including options, futures, swaps, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of both:
- an executive oversight committee consisting of senior management representatives, and
- a risk committee consisting of business unit managers.
Our intention is that any increases or decreases in the value of these contracts will be offset by an opposite change in the value of the item at risk. We enter into all of these contracts for purposes other than trading.
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The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative, it is recorded on the balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. If a derivative qualifies for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported in accumulated other comprehensive income; otherwise, the changes are reported in earnings.
For a derivative instrument to qualify for hedge accounting:
- the relationship between the derivative instrument and the item being hedged must be formally documented at inception,
- the derivative instrument must be highly effective in offsetting the hedged item's cash flows or changes in fair value, and
- if hedging a forecasted transaction, the forecasted transaction must be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or losses are recorded in accumulated other comprehensive income, those gains or losses will be reclassified into earnings in the same period or periods the hedged forecasted transaction affects earnings. If a cash flow hedge is terminated early because it is determined that the forecasted transaction will not occur, any gain or loss recorded in accumulated other comprehensive income at that date is recognized immediately in earnings. If a cash flow hedge is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and then reclassified to earnings when the forecasted transaction affects earnings. The ineffective portion, if any, of all hedges is recognized in earnings.
To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third-party valuations), if available. For certain contracts, this information is not available and we must use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of counterparties.
The majority of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:
- they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MW of electricity or bcf of natural gas),
- they qualify for the normal purchases and sales exception, or
- there is not an active market for the commodity.
Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. Similarly, our electric capacity and energy contracts are not derivatives due to the lack of an active energy market in Michigan. If active markets for these commodities develop in the future, some of these contracts may qualify as derivatives. For our coal purchase contracts, the resulting mark-to-market impact on earnings could be material. For our electric capacity and energy contracts, we believe that we would be able to apply the normal purchases and sales exception, and, therefore, would not be required to mark these contracts to market.
The MISO began operating the Midwest Energy Market on April 1, 2005. By operating the Midwest Energy Market, the MISO centrally dispatches electricity and transmission service throughout much of the Midwest and provides day-ahead and real-time energy market information. At this time, we believe that the establishment of this market does not represent the development of an active energy market in Michigan, as defined by
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SFAS No. 133. However, as the Midwest Energy Market matures, we will continue to monitor its activity level and evaluate if an active energy market may exist in Michigan.
Derivative accounting is required for certain contracts used to limit our exposure to commodity price risk. The following table summarizes our derivative instruments:
We record the fair value of our derivative contracts in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets.
GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses 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. As part of the GCR process, the mark-to-market gains and losses associated with these options are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on the balance sheet as a regulatory asset or liability. At December 31, 2005, we had purchased fixed-priced weather-based gas supply call options and had sold fixed-priced gas supply put options.
FTRS: With the establishment of the Midwest Energy Market, FTRs were established. FTRs are financial instruments that manage price risk related to electricity transmission congestion. An FTR entitles its holder to receive compensation (or, conversely, to remit payment) for congestion-related transmission charges.
DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: Long-term gas contracts: The MCV Partnership uses long-term gas contracts to purchase, and manage the cost of, the natural gas it needs to generate electricity and steam. The MCV Partnership believes that certain of these contracts qualify as normal purchases under SFAS No. 133. Accordingly, we have not recognized these contracts at fair value on our Consolidated Balance Sheets at December 31, 2005.
The MCV Partnership also holds certain long-term gas contracts that do not qualify as normal purchases because these contracts contain volume optionality. In addition, as a result of implementing the RCP in January 2005, a significant portion of long-term gas contracts no longer qualify as normal purchases, because the gas will not be used to generate electricity or steam. Accordingly, all of these contracts are accounted for as derivatives, with changes in fair value recorded in earnings each quarter. For the year ended December 31, 2005, we recorded a $149 million gain, before considering tax effects and minority interest, associated with the increase in fair value of these long-term gas contracts. This gain is included in the total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income (Loss). As a result of mark-to-market gains, we have recorded derivative assets totaling $205 million associated with the fair value of long-term gas contracts on our Consolidated Balance Sheets. Because of the volatility of the natural gas market, the MCV Partnership expects future earnings volatility on these contracts, since gains and losses will be recorded each quarter. We expect almost all of these derivative assets to reverse through earnings during 2006 and 2007 as the gas is purchased, with the remainder reversing between 2008 and 2011. Due to the impairment of the MCV Facility, the equity held by the minority interest owners of the MCV Partnership has decreased significantly. Since we have the controlling financial interest in the
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MCV Partnership, we will assume 100 percent of future losses recognized from the reversal of these assets, not just our proportionate share.
For further details on the RCP, see Note 3, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
Gas Futures and Swaps: The MCV Partnership enters into natural gas futures, options, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas. The MCV Partnership uses these financial instruments to:
- ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam, and
- manage price risk by fixing the price to be paid for natural gas on some of its long-term gas contracts.
At December 31, 2005, the MCV Partnership only held natural gas futures and swaps. Because of increases in the market price of natural gas, the fair value of these contracts increased significantly during 2005. As a result of mark-to-market gains, we have recorded derivative assets totaling $223 million associated with the fair value of these contracts on our Consolidated Balance Sheets. Certain of these contracts, representing $172 million, qualify for cash flow hedge accounting and we record our proportionate share of their mark-to-market gains and losses in Accumulated other comprehensive income. The remaining contracts, representing $51 million, are not cash flow hedges and their mark-to-market gains and losses are recorded to earnings.
The contracts that qualify as cash flow hedges are used to ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam. At December 31, 2005, we have recorded a cumulative net gain of $56 million, net of tax and minority interest, in Accumulated other comprehensive income relating to our proportionate share of the cash flow hedges held by the MCV Partnership. Of this balance, we expect to reclassify $15 million, net of tax and minority interest, as an increase to earnings during the next 12 months as the contracts settle, offsetting the costs of gas purchases, with the remainder to be realized through 2009. There was no ineffectiveness associated with any of these cash flow hedges.
The futures and swap contracts that do not qualify as cash flow hedges are used by the MCV Partnership to manage price risk by fixing the price to be paid for natural gas on some of its variable-priced long-term gas contracts. Prior to the implementation of the RCP, these futures and swap contracts were accounted for as cash flow hedges. Since the RCP was implemented in January 2005, these instruments no longer qualify for cash flow hedge accounting. As a result, we reclassified a $29 million gain ($9 million, net of tax and minority interest) to earnings because the hedged forecasted transactions are no longer probable. Additionally, for the year ended December 31, 2005, we recorded an additional $22 million gain associated with the increase in fair value of these instruments. The total gain recognized from these instruments, $51 million before considering tax effects and minority interest, is included in the total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income (Loss). Because of the volatility of the natural gas market, the MCV Partnership expects future earnings volatility on these contracts, since gains and losses will be recorded each quarter. We expect almost all of these futures and swap contracts to be realized during 2006 as the contracts settle, with the remainder to be realized during 2007. For further details on the RCP, see Note 3, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
The MCV Partnership also engages in cost mitigation activities to offset fixed charges of operating the MCV Facility. These cost mitigation activities may include the use of futures and options contracts to purchase and/or sell natural gas in order to maximize the use of transportation and storage contracts when they are not needed for operation of the MCV Facility. Although these cost mitigation activities do serve to offset fixed monthly charges, these 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
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earnings each quarter. At December 31, 2005, the MCV Partnership did not hold any futures or options for the purpose of these cost mitigation activities.
CREDIT RISK: Our swaps, options, and forward contracts contain credit risk, which is the risk that counterparties will fail to perform their contractual obligations. We reduce this risk through established credit policies. For each counterparty, we assess credit quality by using credit ratings, financial condition, and other available information. We then establish a credit limit for each counterparty based upon our evaluation of credit quality. We monitor the degree to which we are exposed to potential loss under each contract and take remedial action, if necessary.
The MCV Partnership enters into contracts primarily with companies in the electric and gas industry. This industry concentration may have an impact on our exposure to credit risk, either positively or negatively, based on how these counterparties are affected by similar changes in economic, weather, or other conditions. The MCV Partnership typically use industry-standard agreements that allow for netting positive and negative exposures associated with the same counterparty, thereby reducing exposure. These contracts also typically provide for the parties to demand adequate assurance of future performance when there are reasonable grounds for doing so.
The following table illustrates our exposure to potential losses as of December 31, 2005, if each counterparty within this industry concentration failed to perform its contractual obligations. This table includes contracts accounted for as financial instruments. It does not include trade accounts receivable, derivative contracts that qualify for the normal purchases and sales exception under SFAS No. 133, or other contracts that are not accounted for as derivatives.
- ------------------------- (a) Exposure is reflected net of payables or derivative liabilities if netting arrangements exist.
(b) Collateral held includes cash and letters of credit received from counterparties.
(c) The remaining balance of our net exposure was from independent natural gas producers/suppliers that do not have published credit ratings. Based on internal credit reviews, we believe that these counterparties are financially strong and creditworthy.
Based on our credit policies and our current exposures, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance.
6: 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,
- a DCCP for employees hired on or after September 1, 2005,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) Savings Plan,
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- 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 most of our current employees, our non-utility affiliates, and Panhandle, a former affiliate. The Pension Plan's assets are not distinguishable by company.
On September 1, 2005, we implemented the DCCP. DCCP provides an employer cash contribution of 5 percent of base pay to the existing Employees' Savings Plan. No employee contribution is required in order to receive the plan's employer contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP cost for the period ended December 31, 2005 was less than $1 million.
SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code; SERP trust earnings are taxable and trust assets are included in consolidated assets. Trust assets were $30 million at December 31, 2005 and $30 million at December 31, 2004. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $35 million at December 31, 2005 and $30 million at December 31, 2004.
401(k): The employer's match for the 401(k) Savings Plan, which was suspended on September 1, 2002, resumed on January 1, 2005. The employer's match is in CMS Energy Common Stock. On September 1, 2005, employees enrolled in the company's 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee's wages. The total 401(k) Savings Plan cost for the year ended December 31, 2005 was $12 million.
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 2005 and 2004.
EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premium for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was less than $1 million for each of the years ended December 31, 2005 and 2004. The ABO for the EISP was less than $1 million at December 31, 2005 and at December 31, 2004.
OPEB: The OPEB plan covers all regular full-time employees covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least ten full years of applicable continuous service. Regular full-time employees who qualify for a disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs at December 31, 2005 are based on the assumption that costs would increase 10 percent in 2005. The rate of increase is expected to be 10 percent for 2006. The rate of increase is expected to slow to an estimated 5 percent by 2011 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 ABO of the MCV Partnership's postretirement plans was $5 million at December 31, 2005 and 2004. The MCV Partnership's net periodic postretirement health care cost for 2005 and 2004 was less than $1 million.
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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 2005 and 2004, and December 31 for 2003. 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 measurement date for the MCV Partnership's plan is December 31 for 2005 and 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 reasonableness and appropriateness.
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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.
Our plan is actuarially equivalent to Medicare Part D and we have incorporated, retroactively, the effects of the subsidy into our financial statements at June 30, 2004, in accordance with FASB Staff Position, No. SFAS 106-2. We remeasured our obligation at 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 implementation resulted in a reduction of OPEB cost of $23 million for 2005 and 2004. The reduction of $23 million includes $6 million for the year ended December 31, 2005 and $7 million for the year ended December 31, 2004 in capitalized OPEB costs.
(b) The Pension Plan's ABO of $1.188 billion exceeded the value of the Pension Plan assets and net balance sheet asset at December 31, 2005. As a result, we recorded a minimum liability of $481 million. Consistent with MPSC guidance, Consumers recognized the cost of their minimum liability as a regulatory asset. Accordingly, Consumers minimum liability includes an intangible asset of $52 million and a regulatory asset of $399 million. The ABO for the Pension Plan was $1.082 billion at December 31, 2004.
We remeasured our Pension and OPEB obligations at April 30, 2005 to incorporate the effects of the collective bargaining agreement reached between the Utility Workers Union of America and Consumers. The
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net periodic pension cost increased $13 million for 2005 and OPEB benefit costs increased by $2 million for 2005.
Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:
- ------------------------- (a) At November 30, 2005, there were zero shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. At November 30, 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.
We contributed $62 million to our OPEB plan in 2005 and we plan to contribute $62 million to our OPEB plan in 2006. We did not contribute to our Pension Plan in 2005 and we plan to contribute $12 million to our Pension Plan in 2006.
We have established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified across the Standard & Poor's 500 Index, with lesser allocations to the Standard & Poor's Mid Cap, the Small Cap Indexes and a Foreign Equity Index Fund. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. Annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation.
We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers, and through direct contributions from the non-utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in a Standard & Poor's 500 Index fund. The fixed-income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed-income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.
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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 prescription drug subsidy payments.
7: 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 $25 million.
If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, gas transmission and electric and gas distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. In addition, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS: This Interpretation clarified the term "conditional asset retirement obligation" as used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments qualify as a conditional ARO, as defined by FASB Interpretation No. 47. Our asbestos abatement ARO is included in the tables within this footnote. This Interpretation is effective for us on December 31, 2005.
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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 ARO liability at January 1, 2004 and December 31, 2004 in the preceding tables reflect the ARO liability as if FASB Interpretation No. 47 had been in effect at that time, as required by the Interpretation. Our financial statements for those periods do not reflect the asbestos abatement ARO. As required by SFAS No. 71, we accounted for the implementation of this Interpretation by recording a regulatory asset instead of a cumulative effect of a change in accounting principle. There was no effect on net income.
In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and related
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accounting and ratemaking issues for MPSC-jurisdictional electric and gas utilities. Utilities filed responses to the Order in March 2005; the MPSC Staff and intervenors filed responses in May 2005. On December 5, 2005, the ALJ issued a proposal for decision recommending that the MPSC dismiss the proceeding. Exceptions and replies to exceptions have been filed. We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities. We cannot predict the outcome of the proceeding.
8: INCOME TAXES
We join in the filing of a consolidated federal income tax return with CMS Energy and its subsidiaries. Income taxes generally are allocated based on each company's separate taxable income in accordance with the CMS Energy tax sharing agreement. We had tax related payables to CMS Energy of $128 million in 2005 and tax related receivables from CMS Energy of $4 million in 2004.
We utilize deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service life of related properties. We use ITC to reduce current income taxes payable.
AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2005, we had AMT credit carryforwards in the amount of $21 million that do not expire, tax loss carryforwards in the amount of $98 million that expire in 2021 through 2024, and charitable contribution carryforwards in the amount of $13 million that expire in 2006 through 2009. We do not believe that a valuation allowance is required as we expect to utilize all of the carryforwards prior to their expiration.
The significant components of income tax expense (benefit) 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 non-current according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.
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The principal components of our deferred tax assets (liabilities) recognized in the balance sheet are as follows:
In August 2005, the IRS issued Revenue Ruling 2005-53 and regulations to provide guidance with respect to the use of the "simplified service cost" method of tax accounting. We use this tax accounting method, generally allowed by the IRS under section 263A of the Internal Revenue Code, with respect to the allocation of certain corporate overheads to the tax basis of self-constructed utility assets. Under the IRS guidance, significant issues with respect to the application of this method remain unresolved and subject to dispute. However, the effect of the IRS's position may be to require Consumers either (1) to repay a portion of previously received tax benefits, or (2) to add back to taxable income, half in each of 2005 and 2006, a significant portion of previously deducted overheads. The impact of this matter on future earnings, cash flows, or our present NOL carryforwards remains uncertain, but could be material. We have recorded an increase in our taxable income of $359 million in 2005, and a corresponding reduction in deferred taxes related to property, to reflect the estimated 2005 effect of the new regulation.
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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:
On December 31, 2005, $12 million of general business credit carryforwards, net of federal income tax, expired for which a full valuation allowance had been provided. The net change in the deferred tax asset of $12 million was offset by the $9 million reduction in the valuation allowance and reversal of unamortized ITC, net of federal income tax, of $6 million.
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 "simplified service cost method" described above is currently under audit by the IRS. Our estimate for the potential outcome for any uncertain tax issues is highly judgmental. We believe that our accrued tax liabilities at December 31, 2005 are adequate for all years.
9: 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. The Plan has a 5-year term, expiring in May 2009. The Plan includes the following types of awards:
- restricted stock,
- stock options,
- stock appreciation rights,
- phantom shares,
- performance units, and
- management stock purchases.
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.
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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.
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 the time of grant. These shares are subject to forfeiture if employment terminates before vesting.
Performance units have an initial value that is 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.
Select participants may elect to receive all or a portion of their incentive payments under the Officer's Incentive Compensation Plan in the form of cash, shares of restricted common stock, shares of restricted stock units, or any combination of these. These participants may also receive awards of additional restricted common stock or restricted stock units, provided the total value of these additional grants does not exceed $2.5 million for any fiscal year.
Under the 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 4,931,130 shares of CMS Energy Common Stock may be issued at December 31, 2005. All grants awarded under this Plan in 2005 were in the form of restricted stock.
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The following table summarizes restricted stock and stock option activity:
At December 31, 2005, 660,137 of the 1,141,316 shares of restricted stock outstanding were subject to performance objectives.
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. Compensation expense for restricted stock was $3 million in 2005, $2 million in 2004, and $4 million in 2003. Compensation expense for stock options was $3 million in 2003.
The following table shows the weighted average grant date fair value of restricted stock and stock options:
- ------------------------- (a) There were no stock option grants during 2005 or 2004.
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We estimate the fair value of stock options using the Black-Scholes model. We used the following assumptions in the Black-Scholes model:
- ------------------------- (a) There were no stock option grants during 2005 or 2004.
The following table summarizes our stock options outstanding at December 31, 2005:
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. Companies must expense this value over the required service period of the awards. This 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 including the timing of expense recognition for share-based awards with terms that accelerate vesting upon retirement. As a result of these clarifications, future compensation costs for share-based awards with accelerated vesting provisions upon retirement will need to be fully expensed by the period in which the employee becomes eligible to retire. At December 31, 2005, unrecognized compensation cost for such share-based awards held by retirement eligible employees was not material.
SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. The modified prospective method applies the recognition provisions to all awards granted or modified after the adoption date of this Statement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective.
The SEC issued SAB No. 107 to express the views of the Staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. Also, the SEC issued SAB No. 107 to provide the Staff's views regarding the valuation of share-based payments, including assumptions such as expected volatility and expected term. We applied the additional guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R) with no impact on our results of operations.
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10: LEASES
We lease various assets, including service vehicles, railcars, construction equipment, office furniture, and buildings. 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. In November 2003, we exercised our purchase option under the capital lease agreement for our main headquarters building in Jackson, Michigan.
We are authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. The following table summarizes our capital and operating lease expenses:
- ------------------------- (a) Capital lease obligations totaled $59 million at December 31, 2005.
Minimum annual rental commitments under our non-cancelable leases at December 31, 2005 are:
- ------------------------- (a) 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. At December 31, 2005, finance lease obligations totaled $276 million, which represents the third-party portion of the MCV Partnership's finance lease obligation. Total charges under the MCV Partnership's finance lease obligation were $97 million in 2005 and $105 million in 2004. For additional details on transactions with the MCV Partnership and the FMLP, see Note 3, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration Venture."
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11: PROPERTY, PLANT, AND EQUIPMENT
The following table is a summary of our Property, plant and equipment:
- ------------------------- (a) Capital leases presented in this table are gross amounts. Accumulated amortization of capital leases was $54 million at December 31, 2005 and $49 million at December 31, 2004. Capital lease additions were $12 million and capital lease retirements and adjustments were $7 million at December 31, 2005. Capital lease additions were $3 million and capital lease retirements and adjustments were $1 million at December 31, 2004.
(b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2005 and $26 million at December 31, 2004, which is not subject to depreciation.
(c) At December 31, 2005, accumulated depreciation, depletion, and amortization is comprised of $4.803 billion from public utility plant and $1 million from our non-utility plant assets. At December 31, 2004, accumulated depreciation, depletion, and amortization included $5.664 billion from our public utility plant and $1 million related to non-utility plant assets.
(d) At December 31, 2005, public utility plant additions were $450 million and public utility plant retirements, including other plant adjustments, were $64 million. At December 31, 2004, public utility plant additions were $547 million and public utility plant retirements, including other plant adjustments, were $91 million.
(e) Included in net property, plant and equipment are intangible assets primarily related to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization lives for software development costs are seven and twelve years. The estimated amortization life for leasehold improvements is the life of the lease. Other intangible amortization lives range from 50 to 105 years.
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The following tables summarize our intangible assets:
Pre-tax amortization expense related to these intangible assets was $19 million for the year ended December 31, 2005, $19 million for the year ended December 31, 2004, and $19 million for the year ended December 31, 2003. Intangible assets amortization is forecasted to range from $12 million to $22 million per year over the next five years.
(f) The following table illustrates the depreciable life for electric and gas structures and improvements:
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12: JOINTLY OWNED REGULATED UTILITY FACILITIES
We have investments in jointly owned regulated utility facilities as shown in the following table:
- ------------------------- (a) Net investment is the amount of utility plant in service less accumulated depreciation.
The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant's undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities.
13: REPORTABLE SEGMENTS
Our reportable segments are strategic business units organized and managed by the nature of the products and services each provides. We evaluate performance based upon the net income of each segment. 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 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 electric and gas segment where it is appropriate. We allocate accounts between the electric and gas segments where common accounts are attributable to both segments. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, other operation and maintenance expense, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue. Pension provisions are allocated based on labor dollars.
We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income (loss) available to common stockholder by segment. The "Other" segment includes our consolidated special purpose entity for the sale of trade receivables, the MCV Partnership and the FMLP.
The following table shows our financial information by reportable segment:
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- ------------------------- (a) At 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.
(b) Amounts include a portion of our other common assets attributable to both the electric and gas utility businesses.
(c) Amounts include electric restructuring implementation plan, purchase of nuclear fuel, and capital lease additions. Amounts also include a portion of capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
14: CONSOLIDATION OF VARIABLE INTEREST ENTITIES
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. Therefore, we consolidated these partnerships into our consolidated financial statements as of and for the years ended December 31, 2005 and December 31, 2004.
These partnerships have third-party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004. The creditors of these partnerships do not have recourse to the general credit of Consumers.
At December 31, 2005, the MCV Partnership had total assets of $1.318 billion and a net loss of $917 million for the year. At 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: For 2003, the MCV Partnership was accounted for as an equity method investment. Our 49 percent investment in the MCV Partnership was $419 million at December 31, 2003. Our 2003 obligation to purchase electric capacity from the MCV Partnership provided 15 percent of our owned and contracted electric generating capacity. Summarized income statement information of the MCV Partnership follows:
- ------------------------- (a) Revenue from Consumers totaled $514 million in 2003.
(b) Our share of net income was $29 million for the year ended December 31, 2003.
The FMLP is the sole beneficiary of a trust that is the lessor in a long-term direct finance lease with the MCV Partnership. For the year ended December 31, 2003, the FMLP recorded earnings of $32 million related to the direct finance lease.
15: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)
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CONSUMERS ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
- ------------------------- (a) Net of tax.
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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, 2005 and 2004, and the related consolidated statements of income (loss), common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a 49% owned variable interest entity which has been consolidated in 2005 and 2004 and accounted for under the equity method of accounting in 2003. Those statements were audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for Midland Cogeneration Venture Limited Partnership, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Consumers Energy Company at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 7 to the consolidated financial statements, in 2005, the Company adopted Financial Accounting Standards Board (FASB) interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations". As discussed in Note 14 to the consolidated financial statements, in 2004, the Company adopted Revised FASB Interpretation No. 46, "Consolidation of Variable Interest Entities". In addition, as discussed in Note 6 to the consolidated financial statements, in 2004, the Company changed its measurement date for all Consumers Energy Company pension and postretirement benefit plans. As discussed in Note 7 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".
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, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2006 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Detroit, Michigan February 22, 2006
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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 integrated audits of Midland Cogeneration Venture Limited Partnership's 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 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 consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership (a Michigan Limited Partnership) and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9(A), that the Partnership maintained effective internal control over financial reporting as of December 31, 2005 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, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control -- Integrated Framework issued by the COSO. The Partnership'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 the Partnership'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, 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 CE-87
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 20, 2006
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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. CMS ENERGY'S CONTROLS AND PROCEDURES
EVALUATION 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). As described below, under Management's Report on Internal Control Over Financial Reporting, CMS Energy has identified a material weakness in its internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for income taxes. CMS Energy's CEO and CFO concluded that as a result of the material weakness, its disclosure controls and procedures were not effective as of December 31, 2005 and would not have been effective as of December 31, 2004.
To address the control weakness described below, CMS Energy performed additional analysis and other post closing procedures in order to prepare its consolidated financial statements in accordance with generally accepted accounting principles in the United States of America. Accordingly, management believes that the consolidated financial statements for all periods presented in this 2005 Form 10-K fairly present, in all material respects, CMS Energy's financial condition, results of operations, and cash flows.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: CMS Energy's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). CMS Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and includes policies and procedures that:
- pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of CMS Energy;
- provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America, and that receipts and expenditures of CMS Energy are being made only in accordance with authorizations of management and directors of CMS Energy; and
- provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CMS Energy's assets that could have a material effect on its financial statements.
Management, including its CEO and CFO, does not expect that its internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2005. In making this evaluation, management used the criteria set forth in the framework in Internal Control --
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Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, CMS Energy's management concluded that its internal control over financial reporting was not effective as of December 31, 2005 as a result of a material weakness in internal controls surrounding the accounting for income taxes.
A material weakness is a significant deficiency (within the meaning of Public Company Accounting Oversight Board Auditing Standard No. 2), or combination of significant deficiencies, that results in there being a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.
CMS Energy, in connection with the execution of enhanced control processes which reconciled all deferred tax accounts to filed tax returns in the fourth quarter of 2005, determined that certain material errors existed in the deferred tax liability and tax reserve accounts prior to their correction in the 2005 consolidated financial statements. The principal factors contributing to the material weakness at December 31, 2005 in accounting for income taxes were lack of effective controls over the reconciliation of, and adjustments to, CMS Energy's deferred tax asset, deferred tax liability, and tax reserve accounts. CMS Energy did not execute appropriate deferred tax asset and liability account reconciliation procedures at a detailed account level and lacked sufficient review and approval practices within the tax and finance organizations resulting in the errors not being prevented or detected in a timely manner. In addition, CMS Energy did not timely identify required adjustments to its tax reserve account.
CMS Energy's management's assessment of the effectiveness of CMS Energy's internal control over financial reporting as of December 31, 2005 has been audited by Ernst & Young LLP, an independent registered public accounting firm, which audited the consolidated financial statements of CMS Energy included in this Form 10-K. Ernst & Young LLP's attestation report on CMS Energy's management's assessment of internal control over financial reporting is provided elsewhere in this Item 9A.
Material Weakness Remediation Plans as of Date of Filing this Form 10-K: Management believes it has taken steps necessary to remediate this material weakness relating to income taxes; however, all processes and procedures and controls were not in place for an adequate period of time to conclude that they were operating effectively as of December 31, 2005. Accordingly, management will continue to monitor the effectiveness of these processes and procedures and will make any changes management determines appropriate. Summarized below are some of the key processes and procedures:
- Adopting a more rigorous approach to communicate, document and reconcile the detailed components of deferred income tax assets and liabilities;
- Expanding staffing and resources, along with providing training related to the income tax accounting function throughout CMS Energy;
- Implementing additional procedures for tax and accounting personnel related to tax reserve adjustments and in tracking movements in deferred tax accounts recorded by CMS Energy and its subsidiaries; and
- Recording all tax accounting adjustments on each respective subsidiary's books for ongoing tracking, reconciliation and translation, where appropriate.
As noted above, as a result of performing additional analysis and other post-closing procedures, management believes that the consolidated financial statements included in this 2005 Form 10-K fairly present, in all material respects, CMS Energy's financial condition, results of operations and cash flows for the periods presented.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING: Except as otherwise discussed herein, there have been no changes in CMS Energy's internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of CMS Energy Corporation
We have audited management's assessment, included in the accompanying MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that CMS Energy Corporation (a Michigan Corporation) did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of the Company's insufficient controls surrounding the accounting for income taxes, 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, whose financial statements reflect total assets and revenues constituting 8% and 9%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2005. 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.
A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management's assessment. CMS Energy Corporation (the Company) did not maintain effective controls over the accounting for income taxes, including deferred income tax assets and liabilities, tax reserves, and the related income tax provision and disclosures. Specifically, the Company identified the following: lack of effective controls over the reconciliation of its deferred tax asset and deferred tax liability accounts including insufficient or ineffective review and approval practices within the tax and finance organizations resulting in errors not being prevented or detected in a timely manner and lack of timely identification of required adjustments to tax reserve accounts. This material weakness could result in a misstatement of deferred tax assets and liabilities, tax reserves and the related
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income tax provision and disclosures that could result in a material misstatement to annual or interim consolidated financial statements. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2005 financial statements, and this report does not affect our report dated February 22, 2006 on those financial statements.
In our opinion, based on our audit and the report of the other auditors, management's assessment that CMS Energy Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, 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, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, CMS Energy Corporation has not maintained effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.
/s/ Ernst & Young LLP
Detroit, Michigan February 22, 2006
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MCV MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
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.
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, 2005. 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 at page CMS-108.
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ITEM 9A. CONSUMERS' CONTROLS AND PROCEDURES
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES: Under the supervision and with the participation of management, including its CEO and CFO, Consumers 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 is responsible for establishing and maintaining adequate internal control over financial reporting, as 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, 2005.
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, 2005 has been audited by Ernst & Young LLP, an independent registered public accounting firm, which 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 is provided elsewhere in this Item 9A.
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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 the accompanying MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that Consumers Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) maintained effective internal control over financial reporting as of December 31, 2005, 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, whose financial statements reflect total assets and revenues constituting 10% and 11%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2005. 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, 2005, 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, 2005, based on the COSO criteria.
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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Consumers Energy Company as of December 31, 2005 and 2004, and the related consolidated statements of income (loss), common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2005 of Consumers Energy Company and our report dated February 22, 2006 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Detroit, Michigan February 22, 2006
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MCV MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING:
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.
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, 2005. 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 at page CE-87.
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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 of CMS Energy's and Consumers' executive officers is included in CMS Energy's definitive proxy statement, which is incorporated by reference herein.
The following disclosure describes 2006 compensation issues for executive officers, directors and employees.
ANNUAL EMPLOYEE INCENTIVE PLANS
On February 24, 2006, the Compensation and Human Resources Committees (the "C&HR Committees") of the Boards of Directors of CMS Energy and Consumers (the "Boards") approved the payout of cash bonuses under the 2005 Annual Employee Incentive Plan as well as the material terms of the 2006 Annual Employee Incentive Plan (collectively the "Plans"), including the corporate performance goals thereunder. The Plans share the material terms detailed below, although the specific target levels for the corporate performance goals vary from year to year.
CORPORATE PERFORMANCE GOALS: The composite plan performance factor will depend on corporate performance in two areas: (1) the ongoing net income per outstanding CMS Energy common share ("Plan EPS"); and (2) the corporate free cash flow of CMS Energy ("CFCF"). Plan EPS performance shall constitute one-third of the composite plan performance factor and CFCF performance shall constitute the remaining two-thirds of the composite plan performance factor. There will be a payout under the Plans if either a Plan EPS performance factor of at least 95 percent of the target Plan EPS or a CFCF performance factor of at least 83.3 percent of the target CFCF is achieved. If one but not both of these target minimums is achieved, a partial payout would result. The composite plan performance factor to be used for payouts will be capped at a maximum of 200 percent.
ANNUAL AWARD FORMULA: Annual awards for each eligible officer will be based upon a standard award percentage of the officer's base salary as in effect on January 1 of the performance year. The maximum amount that can be awarded under the Plans for any Internal Revenue Code Section 162(m) employee will not exceed $2.5 million in any one performance year. Annual awards for officers will be calculated and made as follows: Individual Award = Base Salary times Standard Award % times Performance Factor %.
The standard award percentages for officers and the annual awards formula for middle management and other employees are based on individual salary grade levels and remain unchanged from the 2005 plan.
PAYMENT OF ANNUAL AWARDS: All annual awards for a performance year will be paid in cash no later than March 31st of the calendar year following the performance year provided that they first have been reviewed and approved by the C&HR Committees, and provided further that the annual award for a particular performance year has not been deferred voluntarily. The amounts required by law to be withheld for income and employment taxes will be deducted from the annual award payments. All annual awards become the obligation of the company on whose payroll the employee is enrolled at the time the C&HR Committees make the annual award.
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COMPENSATION OF DIRECTORS
In connection with the January 26, 2006 meetings of the Boards and the Governance and Public Responsibility Committees (the "G&PR Committees") thereof, the 2006 compensation of the outside members of the Boards and Board committees was confirmed. Directors who are not CMS Energy or Consumers employees receive an annual retainer fee of $30,000, $1,500 for attendance at each Board meeting, $750 per meeting for special telephonic meetings of the Boards and $1,500 for attendance at each committee meeting. The Chair of the Audit Committees receives an annual retainer fee of $7,500 and each other Audit Committee member receives an annual retainer fee of $2,000. The Chairs of the C&HR Committees, Finance and Pension Committees, and the G&PR Committees each receive an annual retainer fee of $5,000. The non-executive Chairman of the Boards (the "Chairman") receives the various elements of the regular non-employee director compensation program as well as an additional annual cash retainer fee of $120,000. The Chairman does not, however, serve on any of the standing committees of the Boards, other than the Executive Committees, and thus does not receive the committee meeting fees or retainers described above.
In 2006, the annual restricted stock award for the non-employee directors will have a fair market value of $45,000 at the time of the May grant. These restricted shares must be held for at least three years from the date of the grant. The Boards have adopted stock ownership guidelines that will align further the interests of the directors with the shareholders. Board members are required to hold CMS Energy common stock equivalent in value to five times their annual cash retainer within five years of becoming a director.
Directors are reimbursed for expenses incurred in attending Board or committee meetings and other company business. Directors who are CMS Energy or Consumers employees do not receive retainers or meeting fees for service on the Boards or as a member of any Board committee. Non-employee directors receive a single retainer fee and restricted share award for service on the Boards and each of their committees, as well as a single meeting attendance fee for concurrent meetings of the Boards or committees.
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) 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.
(a)(3) Exhibits for CMS Energy and Consumers are listed after Item 15(b) below and are incorporated by reference herein.
(b) Exhibits, including those incorporated by reference (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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CMS ENERGY CORPORATION
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
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CONSUMERS ENERGY COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003
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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 24th day of February 2006.
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 24th day of February 2006.
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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 24th day of February 2006.
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 24th day of February 2006.
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CMS ENERGY'S AND CONSUMERS' EXHIBIT INDEX